山脈資源 (RRC) 2009 Q1 法說會逐字稿

Greetings, ladies and gentlemen, and welcome to the Range Resources first quarter earnings conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon, and welcome. Range reported results for the first quarter of 2009 with record production beating the consensus numbers and clearly continuing to execute our business plan for 2009 given the volatility in the commodity markets. The first quarter marked our 25th consecutive quarter of sequential production growth. On the call with me today are John Pinkerton, our Chairman and Chief Executive Officer, Jeff Ventura, our President and Chief Operating Officer, and Roger Manny, our Executive Vice President and Chief Financial Officer. 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 on the home page of our website or you can access it using the SEC's Edgar system.

In addition, we have 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 today. Tables are also posted on the website that will give you detailed information of our current hedge position by quarter. Second, while you are on the home page of the website, we would invite you to view our video report to stockholders for 2008 and get a copy of a primer on modern shale gas development in the United States published by the Department of Energy this month. A PDF copy is available on the left-hand side of the home page. I believe that the primer does an informative -- is an informative resource about the information on various shale plays and the regulatory and environmental issues that many of our investors and the public are asking about.

Third, we are participating in several conferences and road shows in May. Check our website for a complete listing for the next several months. We'll be on the road with RBC Capital in Toronto and Montreal on May 11th and 12th, Calyon Energy Forum in New York on May the 13th, the UBS Oil and Gas conference on May the 19th, and the Deutsche Bank Energy conference in Miami on May the 28th. Our annual stockholder meeting is being held in Fort Worth on May the 20th. We hope that each stockholder has received their proxy materials and urge each stockholder to vote for the proposals being submitted in the proxy. Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the first quarter financial results, I will review some of the key accomplishments so far in 2009. On a year-over-year basis first quarter production rose 12% beating the high end of the guidance. This also marks the 25th consecutive quarter of sequential production growth. The driver for the higher than anticipated production were our exceptional drilling results during the quarter. Our drilling program was on schedule throughout the quarter as we drilled 101 wells. We continue to be extremely pleased with the drilling results and, despite lower natural gas prices, we continue to generate some very attractive returns on our capital. We currently have 15 rigs running versus 33 this time last year. On the financial side our, pardon me, our 12% increase in production was more than offset by a 31% decrease in realized prices.

As a result, our first quarter financial results were lower than the prior period and Roger will get into all the details. However, we're most pleased on the cost side. Our controllable costs were well in line with expectations. Unit operating costs, for example, came in at $0.93 per mcfe, well below last year. In regards to our emerging plays and in particular the Marcellus Shale play, we made significant headway during the quarter. We continued to drill some fantastic wells, expand our acreage position, began indoctrinating our new custom built rigs and continue to build out the infrastructure. In addition, we continue to add some high quality technical people to our team in Pittsburgh that runs our Marcellus play. All in all, I couldn't be more pleased on how we -- what we've done so far in the year. It's a real testimony to the entire team at Range. With that I will turn the call over to Roger to review the financial results.

Thank you, John. The first quarter of 2009 is marked by another record quarter of oil and gas production of 12% from the first quarter of last year, continued good news on unit cost control, and unfortunately, sharply lower oil and gas prices. Oil and gas prices on an mcfe basis were 31% or $2.93 lower than last year. Quarterly oil and gas sales, including cash settled derivatives, totaled $248 million, down 23% from the $322 million in revenues last year, reflecting that the decline in prices more than offset higher production volumes. Cash flow for the first quarter of '09 was $158 million, 34% below the first quarter of '08, with cash flow per share for the quarter coming in at $1.01, $0.04 above the analyst consensus estimate of $0.97. Quarterly EBITDAX of $185 million was 30% lower than the first quarter of '08. First quarter cash margins were down 41% from last year at $4.25 per mcfe compared to $7.15 per mcfe in 2008.

Cash margins received a bit of a boost from an $0.08 per mcfe reduction in cash unit costs from the first quarter of last year, but margins still suffered from lower oil and gas prices. Thanks to the peculiarities of mark to market hedge accounting, despite a 31% drop in oil and gas prices, booked net income actually increased almost 2000%, from $2 million in the first quarter of '08 to $33 million in '09, due to $138 million noncash mark to market hedging loss in last year's number, versus a $31 million noncash mark to market hedging gain in 2009. Quarterly earnings calculated using analyst consensus methodology for the first quarter this year were $38 million or $0.24 per fully diluted share. That compares to an analyst consensus estimate of $0.21. As Rodney mentioned, the Range Resources website contains a full reconciliation of non-GAAP measures mentioned on this call, including cash flow, EBITDAX, and cash margins.

Turning to the expense categories for the first quarter of '09, we see that the trend toward lower cost first visible at Range in mid-2008 has continued. Looking back for a moment, cash direct operating expense unit cost, including work-overs, was $0.96 in the first quarter of last year and it peaked at $1.05 per mcfe in the second quarter of '08. Since then, we have seen this cost decline to $1.00 in the third quarter of '08 and $0.94 in the fourth quarter of last year. As John mentioned, cash direct unit operating costs were $0.93 in the first quarter of '09 and we expect it to stay in the low $0.90 range next year -- or the range of this year. As one would expect, with lower oil and gas prices, production and ad valorem taxes per mcfe were 46% lower that last year's first quarter. Production taxes totaled $0.22 per mcfe for the first quarter of '09, compared to $0.41 last year. G&A expense adjusted for non-cash stock compensation was $0.50 per mcfe for the first quarter of '09.

That's down $0.03 sequentially from the fourth quarter of '08, but up $0.12 from the first quarter of last year. We continue to expect cash G&A expense to increase in '09 as we position our Marcellus Shale team to deliver meaningful future growth. Cash G&A expense unit cost is anticipated to be in the $0.55 to $0.59 range per mcfe for the rest of '09. Interest expense for the first quarter of '09 was $0.71 per mcfe. That's $0.02 higher than the first quarter last year and $0.03 less than the fourth quarter of last year. Exploration expense for the first quarter of '09, excluding noncash stock comp expense, was $12.3 million. That is $3.2 million lower than the first quarter of last year, mostly due to lower dry hole costs. And we anticipate that quarterly exploration expense, including noncash compensation, will approximate $15 million to $18 million per quarter the rest of the year depending, of course, upon our drilling success and the timing of seismic purchases.

Depletion, depreciation and amortization per mcfe for the first quarter of '09 was $2.25. That compares to $2.08 in the first quarter of last year. Now of this $2.25 figure, $2.09 represents depletion expense and $0.16 is attributable to depreciation and amortization of our other assets. Our continuing DD&A rate should hover around the $2.25 per mcfe mark going forward. The first quarter of '09 marks the second quarter we have classified our abandonment and impairment expense related to unproved properties on a separate line item in the income statement. In prior quarters this noncash expense was embedded in the DD&A expense line item. Now we've taken a $19.6 million expense to unproved properties in the first quarter of '09. That compares to $1.4 million in the first quarter of '08, and $36.6 million in the fourth quarter of last year. Let me elaborate for a moment on how the unproved property account works.

When an oil and gas lease is taken, the consideration is recorded to the unproved properties account, which acts as a holding pen for acreage awaiting exploration and development. Now there are three ways that dollars leave the unproved property account. One, a successful well is drilled on unproved acreage and an allocation is made transferring a portion of the unproved property amount to proved properties. Two, unproved acreage is monetized in an outright sale or farm-out to a third party. And three, the leases underlying the unproved property expire or become impaired and the carrying value is written off.

Among the factors that enter into deciding whether an unproved property becomes impaired are -- the acreage expiration date; the terms of the lease; the willingness of the mineral owner to extend or renegotiate; Range's drilling results on the acreage or even a competitor's drilling results on adjacent like kind acreage; the receipt of new data, such as a seismic survey; the size of the capital spending budget; the regional allocation of the capital spending budget; oil and gas prices; cost to drill complete and operate in the area; and the ability to sell or farm-out the acreage. As you can see from this list of factors, almost anything that happens in our business has the potential to impact our estimate of lease [benum] expense and, as you know, a lot has been happening in our industry over the past few quarters.

Now over time, our abandonment expense history will reflect our experience in multiple shale plays and our estimates of acreage abandonment expense should become less volatile and more predictable, but until then the expense figure will continue to vary quarter by quarter. Our best estimate right now of future quarterly noncash abandonment expense is between $16 million and $19 million. Range incurred $19 million in deferred taxes for the quarter, but paid no cash taxes. Our tax rate remains 37%. Now we've received many inquiries recently concerning the new administration's proposal to eliminate all tax preferences for the oil and gas industry. It's too early to predict the likelihood and impact of removing the preferences, as the details of the proposal are not yet known and the legislative process is just getting started.

But what we do know at Range is that we have a $159 million NOL carryforward and approximately $600 million in capitalized intangible drilling costs that we have al -- that we have incurred in prior years but have not yet expensed for tax. So regardless of what happens in Washington, these two items will continue to allow Range to defer cash taxes for many years. For the remainder of 2009, Range has 83% of its cash -- I'm sorry, of its gas production hedged at a floor price of $7.42 per Mmbtu. The hedges are spread across a group of 12 high quality counter parties, ten of which are lenders in the bank -- in the bank credit facility. We also have natural gas basis swaps extending into 2011 with a quarter end net carrying value of $5.8 million. Assuming natural gas prices behave like we anticipate, we will likely begin to hedge 2010 production later this year.

Before we leave the income statement, now that all the year-end results are in for the public companies in our peer group, we're beginning to see independent research emerge that again confirms Range's position as a low-cost operator. The 2008 annual E&P breakeven cost report, published by Banc of America Securities, reveals that Range again has the second lowest breakeven price of the 32 companies in the B of A high yield peer group. This marks the 5th consecutive year in which Range placed either first or second in their report. Now looking at the balance sheet for a minute, there are a couple of items I wish to mention. First, on March 31st, the Range bank group reaffirmed the existing $1.5 billion borrowing base through October of 2009. No changes to the structure or interest rate were required with the reaffirmation.

We believe that our total volume capacity remains well in excess of our current $1.5 billion borrowing base and we have pressure tested the borrowing base at various prices and believe that even in a continued low price environment we have sufficient liquidity to meet our needs. Second, listeners will note that bank debt increased by $114 million during the quarter, reflecting the front loading of some of the 2009 capital spending program, particularly targeted Marcellus acreage purchases that John and Jeff will talk about more in a minute. Also, while we have gone from running 33 rigs last year at this time to 15 rigs this year, it takes several months after a rig is dropped before all the invoices from that rig work through the normal working capital cycle. So we expect to bring the bank debt back down later in the year as capital spending reductions take hold and asset sales occur. Even with the slight increase in debt this quarter, our debt to cap ratio was 43% at the end of first quarter, compared to 47% at the end of the first quarter last year.

In summary, the first quarter of 2009 marks a very solid operating performance with a double-digit increase in production, accompanied by lower unit operating costs. The quarter is also noteworthy for some of the things that we did not experience, such as significant reserve writedowns, infrastructure delays, or poor drilling results. As John mentioned, everything at Range is on track and proceeding according to plan. The lower oil and gas prices have halted the string of record financial results. Range continues to deliver on our core mission, steady reserve and production growth at low cost. John, I'll turn it back to you.

Thanks, Roger. With that I will turn it over to Jeff to review our exploration and development activities. Jeff.

Thanks, John. I'll begin by reviewing production. For the first quarter production averaged 416 million per day, a 12% increase over the first quarter 2008. This represents the highest quarterly production rate in the Company's history and the 25th consecutive quarter of sequential production growth. Let's now review our three key projects. First, I will start with the Marcellus Shale in the Appalachian Basin. The first gas processing plant, which is a refrigeration plant, came on line last October and the capacity of that plant is 30 million per day. The second gas processing plant, a cryogenic plant, came on line in early April, which adds 30 million per day of capacity.. By the end of September, an additional 20 million per day of refrigeration capacity will be added and in early 2010 a 120 million per day cryo plant will start up. In total we anticipate having 200 million per day of processing capacity by early next year.

Range exited 2008 producing roughly 30 million cubic feet equivalent per day net from the Marcellus Shale and had three rigs drilling. Range is on track to exit 2009 with Marcellus production at 80 million to 100 million per day net. We plan on accomplishing this by entering 2009 with three drilling rigs and exiting the year with a total of 6 drilling rigs. The fact that we believe we can [recade] to 100 million per day net by running so few rigs speaks to the excellent quality of the wells that we are drilling and anticipate drilling this year. Although it is very early, we're working on plans for 2010. These plans are preliminary and will be a function of future gas prices, cash flow, well performance, board approval, et cetera, but given all of the above, our early estimate is that we'll probably exit 2010 at double our 2009 exit rate. Two of the three rigs that we have drilling in the Marcellus are our new custom designed rigs.

By year end all six rigs will be specifically designed for our applications. Even though we just began drilling with the new rigs, these rigs are already exceeding expectations. Typical time to move one of the old rigs between wells on the same pad was two days. Now we can move it in four hours or less. I expect that our team will continue to make significant headway in improving performance. We believe the Marcellus Shale has excellent economics. We currently are estimating average reserves per well to be 3 bcfe to 4 bcfe in the areas where we're drilling and the cost to drill and complete in a development mode to be $3 million to $4 million per well. Assuming the midpoint of both ranges and a $7.00 per mcf NYMEX gas price, the rate of return is 75% and the F&D is $1.16 per mcfe.

At $5 per mcf NYMEX flat for the life of the well, the rate of return is 46%. Assuming the same reserves and cost, NYMEX could drop to $3.25 per mcf and these wells would still have a 20% rate of return. Our acreage position in the Marcellus fairway is nearly 900,000 net acres. The 900,000 net acres equates to more than 15 tcfe to 22 tcfe of net un-risk resource potential. Of that 10 tcfe to 15 tcfe are located in the southwest part of the play, with the remainder in the northeast. We currently have the record for the highest rate vertical well, which is in the northeast and tested for 24 hours at a rate of 6.3 million per day. Range also holds the record for the highest rate horizontal well in the play too, which is 24.5 million cubic feet equivalent per day in the southwest part of the play. The 24.5 million cubic feet equivalent per day well actually cleaned up some after we reported it and its best 24 hour rate to sales was 26 million per day. For the best 30 days to sales, this will average 10.8 million per day.

Our next best three wells produced two sales at rates of 10.3 million, 10.1 million and 9.1 million cubic feet equivalent per day for their best 24 hour rates. For the best 30 days they averaged 4.3 million, 7.2 million and 7.6 million cubic feet equivalent per day. The well that we announced in our press release yesterday that was testing at 10.7 million per day continues to clean up and it likes like its peak 24 hour rate will be 13.5 million cubic feet equivalent per day at a flowing tubing pressure of 1250 pounds. In addition, in yesterday's release we drilled and completed another Marcellus well for 7.9 million cubic feet equivalent per day. In addition to pursuing the Marcellus Shale, we're starting the Utica, Berquette, Middlesex, Genesee and Rinestreet Shales. There is good potential for all of these horizons on our existing acreage in the Appalachian Basin.

The prospective areas of these unexploited shale targets largely occur within Range's core Marcellus acreage position, thus allowing for stack pay opportunities and operational efficiencies in resource development. Range owns a total of 2.7 million gross or 2.3 million net acres of leasehold in the Appalachian Basin. Another very impactful low risk project for us in the Appalachian Basin is our Nora area located in Virginia. There is significant upside for all three horizons in Nora, CBM, tight gas sand and the Huron shale. Range continues to drill successful CBM and tight gas sand wells in this field and has over 2150 producing wells here. F&D costs net the range continue to be around $1.00 per mcf, which is amongst the lowest in the country. In addition, the wells produced very little water and have low lifting cost. Given its location in the Appalachian Basin these wells also receive a premium to NYMEX.

The combination of low F&B and low LOE results in a very good rate of return of about 60% at a $7 per mcf NYMEX gas price. At $5 the rate of return is 33%. Given the large number of wells which can be drilled on current spacing and assuming successful down spacing, there are approximately 6,000 wells left to drill. The latest development in Nora is horizontal drilling in the Huron Shale. So far we've drilled and completed nine wells. Of these eight wells have been turned on and have initial 24-hour rates of 1.1 million per day to sales which is very good. The remaining two wells will be turned to sales soon. The Huron Shale has potential of about 1.5 tcf of net gas reserves to Range, The next idea we're testing at Nora is horizontal drilling in the Berea sandstone, which we believe has excellent potential on our acreage. Our first two wells were successful and came on line at rates of 1.5 million and 1.1 million per day.

We'll be drilling 18 additional horizontal wells during the remainder of the year, 13 in the Huron and five in the Berea. The next project I want to discuss is the Barnett Shale in the Fort Worth Basin. Range currently has about 96,000 net acres in the Barnett Shale play. This represents 1.6 tcfe of net un-risk, unbooked upside in the core proven part of the Barnett. Currently we have three rigs running in the Barnett. Although we're running fewer rigs this year, results have been spectacular. Range just set a record for the highest rate well in the Barnett to date by any operator. Our well produced an average of 9.6 million per day for 30 days. I would also like to point out that after thousands of Barnett wells have been drilled and completed, 9.6 million per day is the best. An interesting comparison is after drilling and completing only 35 Marcellus Shale wells our best well there averaged 10.8 million per day for 30 days to sales, which is better than the record Barnett well.

Even though we're only running three rigs in the Barnett, production continues to climb and we're currently producing about 125 million per day net from the play. On our core Barnet acreage, our wells will average about 3 bcf and cost about about $2.6 million. At $7.00 NYMEX this generates close to a 70% rate of return. At $5.00 flat gas for the life of the well the rate of return is 32%. Let me address the cost savings that we're seeing. In the Barnett rig rates for Range one year ago averaged about 20,700 per day. In May we're projecting rig rates to average about 12,500 per day, which is decrease of 40%. By July we're projecting our average rate will be about 10,000 per day. Stimulation costs have also dropped 30% over this period. Tubular prices are also coming down. For example, I will use five and a half N-80. In July of 2008 prices had significantly increased and we were paying 2640 per foot. For July of 2009 we're projecting 1450 per foot.

In the Marcellus we are also seeing significant cost reductions, both from decreasing service costs and our own efficiencies. Rig rates are down in the Marcellus, but not near to the degree in the Barnett, since the pace of drilling is actually increasing in the Marcellus versus declining in the Barnett. Frac costs are down significantly, though. We've seen a 44% reduction in costs there for the same job size. We're also seeing considerable cost savings from efficiency improvements with the new custom rigs, new bits, reengineered mud systems, slider, new directional drilling companies, turnkey moves and improved completion designs. We're projecting our development wells for the second quarter of this year to reach 3.5 million to drill and complete. Going forward, Range will be able to do more with less. Our efficiency will improve not only from reduced costs but from the high graded portfolio that we now have.

Even though Range has done a great job of growing production with top of the class all in cost structure over the last five years, it will be even better going forward. Range's growth three to five years ago came from properties like Furman, Conger, Eunice, Corson Ranch and complementary acquisitions. Going forward, our growth primarily will come from the Marcellus, Nora, and the core area of the Barnett. These are all relatively new additions to our portfolio and they all have significantly better economics and the ability to grow producing rates significantly better than the properties that were driving our growth previously. I mentioned the rates of return of these projects earlier and they're all very robust even with low commodity prices. They are among the best rate of return and lowest F&B cost projects in the US. I believe that the Marcellus is the best project in the country, particularly when you couple that with the large reserve upside that it has.

The F&D costs for all three properties ranges from about $1.00 to $1.50, and the LOEs from all three properties are low. It is also important that two of our top three projects are in the Appalachian Basin, where the gas price is better than anywhere else in the U.S. Approximately 90% of our budget will be spent in these three areas. This portfolio has resulted in Range consistently delivering top tier organic production and reserve growth with one of the lowest cost structures in the business. As Roger mentioned, according to B of A's research, considering all in costs which includes F&D, LOE, G&A, interest expense and basin gas price differentials, Range has either the lowest or second lowest cost structure of the group of companies that they cover for the last five years in a row.

This is a direct result of our simple strategy of strong organic growth and top quartile cost structure or better and, in addition, consistently building and high grading our inventory, coupled with one of the best teams in the industry. Range today has more potential upside and lower risk upside than at any time in the Company's history. With our inventory, today we have the opportunity to grow the Company more than 10 fold, primarily from the Marcellus Shale, Nora and the Barnett Shale. We believe our excellent organic growth, coupled with an excellent cost structure will result in continuing to create strong shareholder returns over time. Back to you, John.

Thanks, Jeff, that was a terrific update in terms of what's going on in the field. Let's look forward a little bit. Looking to the remainder of 2009, we see continued strong operating results. For second quarter of 2009 we're looking for production to average 420 million to 425 million a day. This will represent -- the midpoint represents an 11% increase year-over-year. I should note that the second quarter production guidance assumes we sell Furman, the Furman Masco field midway in the second quarter. Furman is currently producing approximately 16 million a day net. We're in process of finalizing the Furman purchase and sale agreement and should be able to provide more of the details very shortly. Looking beyond the second quarter, it gets a little fuzzy due to the impact of the asset sales.

Besides Furman, we have a couple of smaller properties that we're in discussions with potential buyers. All that being said, with the -- with the momentum from the existing drilling results that Jeff talked about that we've had so far this year, we currently believe that we'll achieve our 10% production growth target for the year, even after taking into account the asset sales that we have in progress. Given the reduced capital program, as Jeff mentioned, we're focusing 9% of our CapEx in the Marcellus, Nora, and Barnett plays. These plays generate very attractive returns even at low gas prices. We're fortunate that our remaining properties have a very shallow decline curve. In particular, our tight gas sand properties in Appalachia, for example, are all in a decline of less than 10%. As Jeff mentioned, one of the key elements this year will be the very positive impact on our results will relate to the capital efficiency.

In the past few years, we spent considerable capital in the Marcellus play without seeing any visible return. Beginning October of last year this all changed, as the first phase of the infrastructure was completed and the production began to ramp up. As our Marcellus production continues to ramp up in 2009, we see this capital efficiency impact having an ever increasing impact. As we like to say, this will allow us to do more with less. In the latter half of 2009 and into 2010, this will be even more evident as we get more capital efficiency impact from the Marcellus ramping up, as well as the full benefit of lower service costs. As it relates to our 2009 capital program, Roger discussed that we expended a disproportionate share of our CapEx in the first quarter. This was our plan as we had some key acreage in the Marcellus and to a lesser extent the Barnett that we wanted to tie up.

With that completed, the benefit of the lower service cost and fewer rigs running, the rate of capital spending will decline throughout the remainder of the year. We are looking to capital spending for 2009 and 2010 and how we plan to fund it, a key component was our commitment to asset sales. With the capital efficiency that we're generating from the Marcellus, Nora and the Barnett, we have a number of other properties that have development potential which will not likely see a lot of CapEx allocated to them. Three years ago we made the decision to begin methodical process of selling off such properties like Furman that had plenty of development opportunities but where we saw that we weren't likely to allocate sufficient capital to develop them given the higher and better use of the capital at the other projects.

Besides providing capital to cycle into the high return projects, we believe this will result -- will continue to result in lowering our cost structure and it will focus our capital -- our technical teams on high return projects and will ultimately result in issuing less equity. As I have said many times in the past, at Range we care a lot about our stock price but not much about our market capitalization. We are confident that when we combine our cash flow with the asset sales that we have in process, we will have sufficient capital to execute our capital program for the remainder of 2009 and through 2010 while maintain a strong balance sheet. We anticipate that the majority of the asset sales will be completed in the second quarter. As a result this will allow us to be patient, discipline as we look to hedge our 2010 production later this year. One item I have not mentioned as a source of CapEx funding is the issuance of equity.

Over the years, our strategy has been to issue equity only when we've had a clear use of the proceeds. This reflects our belief that if we maintain a disciplined approach towards issuing equity, we have a much better chance of driving up our stock price over time. Recently, we've had several investors and or analysts suggest that Range will break ranks with this strategy and issue equity because, quote, we have an attractive stock price. I believe strongly the best way to increase our stock price is A, execute our business plan, which we're doing, and B, not issue equity unless we have a clear use of proceeds. Because our asset sales are proceeding as planned, our drilling results are generating terrific results, our costs are coming down, and we have minimal future drilling commitments, we do not see a clear use of proceeds and therefore I can say very clearly we have no plans to issue equity at the current time.

With regards to our valuation, we truly appreciate that our shareholders have confidence in our ability to continue to generate attractive returns. We don't get too balled up in comparing our valuation to that of our other companies. Obviously we have a much more intimate understanding of Range's value and its potential. Based on this understanding we believe that our NAV per share is substantially higher than our current stock price. As we continue to execute our plan, this will become clearer to everyone. The bottom-line is, if the Marcellus continues to drill out and the wells average 3 bcf to 4 bcf each and they cost $3 million to $4 million to drill and complete, Range is clearly a triple digit stock. It's our job to execute and make this real for our existing shareholders. That being said, at Range there are multiple ways to win. We have a substantial posit -- potential, as Jeff discussed, in both Nora and the Barnett and many of our other properties that can more than double and triple our proved reserves.

Although extremely important, we're not betting the ranch on the Marcellus. I should also mention there are other horizons, besides the Marcellus and Appalachia to provide plenty of additional potential and as Jeff mentioned as well. In summary, looking at Range today, we have the largest drilling inventory in our history with over 10,000 projects. Our inventory together with our emerging plays represent 20 tcf to 28 tcf of future growth potential. This equals seven to ten times our exiting proved reserves. While we are excited about the growth potential at Range, we are intently focused on delivering each and every quarter. The first quarter of 2009 is a shining example of this commitment by all the employees at Range. With that, operator, let's open the call for questions.

(Operator Instructions). Our first question comes from the line of Jeff Hayden with Rodman & Renshaw. Please proceed with your question. Hi, guys. Hi, Jeff.

Couple quick questions. Just curious about the Marcellus acreage position. You guys have kind of been saying about 900,000 for awhile, yet you've continued to add some acreage. Just curious has there been some acreage you've been (inaudible) out of the core fairway as you continue to add or are you just kind of staying conservative with the 900 and we should really think it is higher than that?

A good question. We obviously, just to step back, we own 1.4 million acres, net acres in the outline of the Marcellus. As you pointed out, we've kind of, quote, high graded about 900,000 of that. And we continue to add acreage. We also -- there's some of the acreage in there, especially in the areas where we haven't high graded part of the 500,000, so to speak, that's expiring and/or we are letting go or we're selling to third parties or we are farming out to other operators. All that being said, not trying to be coy, the 900,000 is still around the 900,000 in terms of all that and, again, I don't think we ought to be focused on whether it's 925 or 875 or 880, quite frankly. I think the key is, is that continue to drive up production along what we're doing. The acreage we are buying, and I want to stress this, the acreage we are buying is we're not buying any trend acreage in the play.

We haven't really done that, even last year we weren't doing that. The acreage we're buying or leasing or farming in is in and around these good wells that Jeff mentioned and we're filling in all those holes. We're trying to fill in the holes. The only problem is there's a lot of holes and they're pretty big. So it's a lot of opportunity. But we're going to be disciplined as we go through that. But the good news is, obviously, acreage prices are coming down. We're getting it a fair amount cheaper.

Let me just add to that a little bit. When we talk about the 900, roughly 900,000, about 550,000 is in the southwest, 350,000 in the northeast. We have big positions in both areas. The other thing that's interesting at this point in time with all the activity we've had, which is a large number of wells, coupled with excellent results from Chesapeake and CNX and Atlas and Equitable, a lot of the risk has been taken out of that piece of the acreage. Now that's a lot of reserves to range. So I feel good so far really. A lot of the wells in that area, basically they're all good. So that's exciting. Just in terms of what's been, quote, de-risk -- of course, you like to see 1,000 wells there and 10,000 and in time I think you will see that, but the risk clearly is coming down and the potential of the wells looks excellent.

Okay, appreciate it. And just one other real quick one. On the two recent wells you guys reported, can you give us any color on lateral link, number of frac stages, et cetera, that you use on those?

Yes, I mean, so far we've not given out real specifics. We have said in general the designs are similar to what you see in the Barnett, in terms of lateral links and number of stages, but for a little while longer I think we'll hold on to that. We're -- we're still trying to work and optimize that and the guys are doing an excellent job. Obviously we're drilling some great wells, not with just great IPs, but wells that hang in there 30 days, 60 days. Our oldest horizontal well now has been on-line really almost two years. When we plot those up versus the Barnett wells, we're active in the Barnett, of course active in the Marcellus. They plot very favorably. Real excited with what we have and where we are at this point in time.

All right, appreciate it.

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

Afternoon, guys. Jeff, on -- on again going back to last few wells, any thoughts as to the variability in the 30-day performance? Some of them are holding up much better than the others. Whatever you (multiple speakers).

Well, when -- when you look at any wells and it's easy to pick the more mature shale plays, like the Barnett. When you look within Tarrant County, which is the best part of the Barnett, you see variability in the wells. That's true in Fayetteville. It is true in the Woodford. It is true at conventional plays. It is true onshore, offshore. It is similar. All in all, I'm very excited. Though like I said, when you look at that area, and I haven't counted the wells recently, but between CNX and Atlas and Chesapeake and Range and Equitable and others, there's got to be over 250 wells down in the southwest, and that's across a large area. And I haven't measured it recently, but I will bet some of our wells are as for as 40 miles apart, which is pretty far, and we're seeing -- we're seeing good results across that kind of position. So that's why I'm excited about it. Northeast is going to be great at well.

I complimented one of my brethren from Cabot who used to work with Tenneco as well, at the Doug conference, Mike, and they're doing a great job up there. The northeast is going to have some good areas. We've got 350,000 acres up there. We have drilled some good wells in Lycoma County. So there's going to be winners and losers in the play, good area and bad areas. but clearly all those companies that I mentioned have drilled a number of excellent wells.

Right. Maybe I'm not ready to share it yet so I'll give you an easy out there, but what will it take to, keeping in mind the results that you have, what will it take to go revisit that 3 million to 4 million and three bcf to four bcf that seems conservative enough at this point?

I'm glad you asked that, Rehan. A lot of people asked that. They are saying, you have announced -- and I just went through some of our top wells and how they've performed initially 30 days and our oldest well, like I said, two years. Clearly when I'm talking about wells like that they're much better than that. Those wells are going to be 5 bcf to 10 bcf. They're excellent -- they are excellent wells. I'm comfortable right now, when we talk about 550,000 acres, that's a huge position, or we talk about 900,000 acres, that's massive. And again, I'd just come back to and a lot of people challenge me on that and challenge our team, but I'd come back and I'll argue if we can hit the midpoint of that range, 3.5 million for 3.5 b's, finding costs for $1.16. They worked down to $3.00 gas, I'll do that all day long. And I think long run gas is going to be $6.00 to $8.00 in mcf.

I don't know of any other play in the US that's better than that that has that kind of scale and magnitude and repeatability. And maybe there is another one out there, but I'm not aware of what it is. And you couple those results with the fact that we're in the Appalachian Basin and we are getting a premium to NYMEX and the low royalties that we have, it's hard to beat those economics. Could they be better? Absolutely. Are some of these high-end wells I am talking about they are much better than 3 bcf to 4 bcf. I'm not saying they're -- those wells are 3 to 4 bs. I am just saying when you think in terms of broad acreage positions I think that's a reasonable number based on would I see. Maybe it's better, who knows. Time will tell. Again I'd come back to if you look at the best part of the Barnett, Tarrant County, the wells, I think, average 3, 3.5bs, probably like 3.2 on average. So I'm really excited by where we are. But I understand where you are trying to go. I just think it's early. Could happen, though.

All right. So you need, what, another year before you revisit?

Well, we look at it all the time. But I think I would like to see a larger sample, more wells, more history before we're going to move off that. At a minimum, we're probably going to stick with what we are at least through the end of the year. So probably end of the year, early next year when we finish year end reserve. We'll probably revisit what we think the averages are. And as we drill more wells and other people drill more wells, that helps prove up parts of the play or disprove parts of the play and we'll get more specific. Hopefully in time, I know everybody wants those details. We try to give out a little bit more, a little bit more every time, but it's still a very competitive play.

It is one of the few places in the US where people with rig counts increasing rather than dropping. So that's the reason. And again, the State of Pennsylvania, there's an advantage and I appreciate that the state has it, that you can keep the production information confidential for five years. That's why we were willing, one of the reasons, we were willing to risk a lot of money. So that's the competitive advantage we have. Not only do we have a large acreage position, but we have more data than really anybody else out there.

I've got more questions but I'll yield the floor for now.

Thank you. Our next question is from the line of Tom Gardner from Simmons & Company. Please proceed with your question.

Good afternoon, guys.

Hello, Tom.

In the past you have characterized the infrastructure situation in northeast Marcellus area as more challenging. Can you walk us through those challenges and the progress you are making to overcome them? And perhaps the future development timing in the area as well.

Well, yes, it's good to put it in perspective. If you think about the -- how Pennsylvania in particular has been drilled out, a lot of these shallow drilling has taken place in the southwest part of the state. So there -- that is where the greatest amount of pipelines and gathering systems and all that kind of stuff is. So even though in some respects those lines are not capable of big, high pressure wells in a big development, they do provide a good way to test wells and it's kind of a starter kit to get started. Also, the right of ways are already defined. You can go in there and just dig another ditch and throw the pipe in there and good on down the road. So that -- that -- and in some of the biggest pipelines in the US run right through that part of the state. So when you take all of that, that's the reason why we said that.

When you look to the northeast -- the other thing is people are just more used to oil and gas drilling in the southwest than they are in the northeast. And there's also -- there tends to be more forest lands and more state lands up there. With all that being said, there is -- we're working on some infrastructure up in the northeast as we speak. Cabot has done a good job of getting their wells tied in and what not. So, like I've said all along, I think one of the misconceptions about the Marcellus play is they quote, the infrastructure is going to take longer. I tend to disagree with that. When you think about -- when you think about infrastructure, again, some of the biggest pipelines in the US run right in the middle of this and so it's really a midstream question or midstream issue, just tieing in the midstream and you've got huge take-away capacity on those big pieces of pipe that flow to the northeast. Much greater, multiples greater than when we started out in the Barnett and when these other places started out.

So again, it's just degrees of -- we're just talking about degrees there. I think in time all of it has a good way. As Jeff mentioned, you're in one of the best gas markets in the world. I've said more than once, two-thirds of the people in the United States -- in the United States live within 350 miles around the City of Pittsburgh. So, if you have natural gas, that's where you want to sell it.

Given what you said and the proximity to major pipelines, it appears that the processing bottle, the natural gas processing appears to be kind of the chief bottleneck in the area. Do you or are you focusing your drilling on dry gas areas to circumvent that bottleneck.

Tom, I would just point out anything in the northeast is going to be dry. Doesn't need to be processed. Even when you go to the southwest the whole area doesn't need to be processed. It's just as you get off to the western side of it. So we've got a lot of acreage that's in both areas. So we'll be drilling in the wet gas. One, like I said, we will have by really the end of this year, early next year, 200 million a day of takeaway capacity. We are talking about exit rate for 2010 being double what we end this year at, so we'll be -- the capacity even in -- if it were wet gas only, is going to be double what we are -- double what we need. So it is going to built a year ahead of time.

But we'll also be working on takeaway -- we have takeaway capacity in some of the dry areas in the southwest and by the end of next year we will have takeaway capacity in the northeast. And we're -- we ramped up in the southwest first, one, because we like the area a lot and it is where we started and two, we had succuss really almost from -- from day one with our original rinse well there. We can ramp up quicker for the reasons John said. So that is why we are doing that, but next year you will see us -- we'll continue to ramp up in the southwest, but we will start drilling in the northeast as well and by the end of 2010 we will have production from both areas.

Yes and there's some advantages, I mean advantages and disadvantages of wet gas. One, the disadvantage you are going have -- you have got to process it, but that in time solves itself because you build a gas processing plant just like we did. The good news, though, is is that because you are getting very high BTU gas, the economics are better, and so -- so it's the chicken or the egg, but we think over time those will kind of solve themselves and you are going down the road.

I would add, even after processing in the wet gas area, the gas that we sell is still about roughly 1150 BTUs. And we get paid for the BTUs. So you take -- you take NYMEX times 1.15, 15% up lift, which is very significant, and then add the basin differential to that.

Plus -- plus you get the share of the liquid that you get from the plant. So it is -- there's a lot of benefit there when you're running through your economics and you calculate the real of bottom-line economics, all that stuff needs to be taken into account. The one thing I would also like to say is that, and again, I will compliment our friends over at Mark West, is that in joint with them, and I'll give them all the credit, we've built the first large scale gas processing plant ever in the State of Pennsylvania. We've been able to do it in lightning speed. I really compliment them. And it also, I think, goes to the testament that the people, they want us there. The regulators, although, they want it done right, which we agree with. They got after us -- the permits were given in a reasonable amount of time and we got out there and made it happen. Again, I think it is -- it's -- to -- basically March of last year and six months later having that gas flowing is really a just a -- it really was an incredible feat. So I don't look at that as a bottleneck as much as I really did think that we did it in kind of lightning -- lightning speed, so to speak.

I got you. Just one last quick question here with regard to the Nora well. Did you do anything different to that well to achieve that record rate and do you (multiple speakers.?

You're talking about the well that -- no, (multiple speakers).

The Nora (inaudible).

I think one, again I'd compliment Jerry Grantham and his team there that runs that for us and Steve Grose that looks over that division. Our guys in general, Range is -- we're in a good partnership with Equitable. They are working the CBM, we are working the tight gas sands and the shale. And then they, of course, they operate it once they are drilled and completed. Our guys have done a really good job of, let's say, targeting specific areas and completing the wells a little bit different and then -- so it's a combination. When you get a well that good, and remembering, those wells are only about -- that well is about 3400 feet deep, roughly, or they are 30 -- those kind of Ravenscliff wells can range from 3,000 to 4,000 feet deep. When you find wells like that, that average over three million a day for 30 days to sales, you get excellent economics, quick payouts, so Jerry and his team have drilled a number of great wells down there. We talk about the CBM a lot, but those tight gas sand wells are great down there. Obviously, that one is not too tight because it's doing pretty good.

Can you -- horizontal development there? Is that a possibility?

What you have is, you have and I'm trying to describe this. It would be easier if I could draw it for you. You have the CBM on top and then the traditional big horizon is at Brea. And in Berea we're looking at horizontal drilling because it covers more areas. But in between the tight gas sand and the Brea, so in between about 2800 feet and 5,000 feet, you have another -- a number of other horizons like the Ravenscliffs and Big Lime and there is other formations. The Ravenscliffs tend to be channels that run through there. So if we continue to drill or in-fill drill, we have encountered a good Ravenscliff area and we've seen some of that before. We haven't announced those other wells.

That one was just interesting because the original development of that field was in those deeper sands and yet here we are 30, 40 years later and drilling the best wells ever out there. Typically in time, you think the wells are -- the quality of the wells would get poorer, these wells are -- they are actually getting better or -- that set a new record. But the Ravenscliff I don't think is a good horizontal target, a long answer to your question. But the Brea, I think, is, the Big Lime is and there's a number of other horizons there that I think will be.

Thank you, guys, I really appreciate the color.

Thank you.

Thank you. Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question.

Good afternoon. Jeff, I think you started to touch on this activity in northeast Pennsylvania versus southwest Pennsylvania. Sounds like you will be wrapping up probably in the northeast Pennsylvania towards the end of the year. How do you look at your 60 plus rigs or wells that you plan to drill this year in terms of southwest versus the northeast part of the state?

For this year they're all predominantly going to be in the southwest and it's really early. Next year, though, you will see significant drilling in the northeast. And we looked carefully at the development plan and we want to ramp up production in order to get a good return on our investment, generate value for our shareholders. And when you look at the length of the leases and the timing to getting it on market and where we started, all those things are parts of the decisions that cause us to time drilling in one area versus another. But you will see us drilling up in the northeast next year. Like I said, really our best vertical well to date is up there. So the wells we're drilling on the southwest are great. I'm excited about the potential in the northeast. Cabot drilled a number of good wells up there. So I think -- we've got 350,000 acres so that's a big -- if you just think of our position in the northeast, that's a pretty big position.

And given the fact you have pretty nice interstate pipelines in that area. You mentioned it's really just a matter of getting -- gathering lines to put in. Is that the biggest issue in northeast P.A.?

Yes and it's just timing and laying out our development. Gas there is going to be (inaudible) roughly 1000 BTUs, so you don't have the -- but the guys are in the process of acquiring the firm transportation. We already have taps and we've got plans for the gathering and we know exactly where we want to start drilling, so we have got a good plan in place. I'm excited about -- this year should be real exciting. Next year should be even more exciting.

And, Roger, for you. Just from a hedging standpoint, I think you -- you mentioned earlier that as you look towards the latter part of this year you probably look to start layering in 2010 hedges. What are some of the trigger points that you are looking for from a hedging strategy standpoint for next year?

Ron, this is John. My thesis, and I'll make this clear, we're not hedging $3 gas.

Right.

And to me it's pretty simple. We -- it took us six and a half years to increase the rig count, natural gas rig count from about 750 rigs to over 1600 rigs and it's taken us seven months to eliminate that, plus go beyond, below that. And it's just going to be a matter of time until you see the supply response and I think when that happens, I think gas, natural gas prices are going to have -- are going to respond very violently. And once that occurs, then we'll take advantage of it and get our hedging done. So that's kind of the theory. And we, quite frankly, we do have some -- some specific numbers and thoughts in mind, but we'll keep those to ourselves a little bit.

Okay. And then --

But I don't think -- but, Ron, I think you can go back. Again, not trying to be coy, but you can go back and look at what we've done historically. It's not going to be too much different from that.

Okay. And I tend to agree with you in terms of the gas price scenario, especially as we get to the latter part of this year. I just didn't know if you were going to have -- in the past, it was somewhat to protect a certain amount of activity levels. Just as you start looking at 2010 versus 2009, especially as northeast Pennsylvania starts to ramp up, I would assume that the outlook would be to continue to ramp your CapEx in 2010 relative to this year, at least focus on the drilling portion of it.

Well, that's a good point. Let me kind of -- let me kind of zero in on that, because I think you said a couple things that we need to clarify and get some clarity and some -- be completely transparent. We, as I mentioned, we're in the process of getting these asset sales. Chad Stevens and his team, who have done a terrific job, are in the process of getting these asset sales signed up, and again, pretty shortly we'll give you some clarity on at least Furman and then the little ones we'll probably talk about next quarter. That is really -- that is the thesis, at least in our view, that between our existing cash flow and those asset sales, we believe confidently that that will generate the cash flow to generate all the capital we need for '09 and 2010, based on current prices. And so we feel pretty confident there. In terms of the comment in terms of capital, again, I think the thing -- I think -- we don't plan on-ramping up capital in 2010.

We don't need to because the capital efficiency between service prices coming down and the capital efficiency that Jeff talked about and the productivity we're getting out of our big three projects, we're not going to need to ramp up capital '10 over 2009 much to get, again, to get very solid growth and hit our business plan and continue to double the production, the rate actual rate in the Marcellus. So I want to be clear there. We're not expecting a big ramp-up in capital in 2010. Obviously, if prices respond, like -- we're actually probably a little conservative than some, but if prices do respond higher than what we think, I could see us increasing capital marginally, but not a whole lot. Again, I think the key -- the key, like Jeff said, the thing that's so exciting about the Marcellus is that you can get a lot of growth rolling just a few number of rigs. And so we're pretty excited about that.

So, it is one of -- again, it comes back to this whole capital efficiency issue that we can do more with less, because the FD&A and just the well results have been -- have been so much better than what -- then what we -- then what we hoped for. And so, therefore, this gives us more confidence that we can do more with less.

And let me add a little bit, another example of efficiency. I was talking to the guy that heads -- Ray Walker, who heads up our Marcellus Shale division, right before the call and we're -- we're -- we do a lot of pre-planning, what do we want to do for the rest of this year, next year, and five and ten years out. And we were talking about, and it's way early and I don't want to throw numbers out, but roughly speaking we were talking about if we double the number of wells in the Marcellus next year as a sensitivity, and I was asking Ray how many more rigs do we need if we do that. And Ray said it depends how efficient we get. There's a chance, I'm not promising this and if it's just anecdotal, but the guy -- you can see the costs really coming down, we may be able to drill double the wells with a similar number of rigs or maybe just a couple more.

You don't need to double the rigs to double the number of wells, because our time on a well, costs for a well, speed on the well is getting so much better with the way that we are drilling. So there's -- it's another efficiency. I am just pointing out I think everybody thinks in a simplistic way of one plus one is two, but it isn't if we can get better and better in terms of what we are doing.

Well, I think -- I think a great example of that, Jeff, is -- is what Southwestern has done recently in the Fayetteville in terms of some of the progress they have made in terms of drilling efficiencies and the quality of wells, what not. And that, again, I think it's one of the things that to me is just so encouraging when I think of these shale plays in general in that in a traditional conventional play, as you drill -- you drill up a field, your well quality tends to get worse over time after you hit kind of the peak. And most the interesting thing in these shale plays is that with -- because there's so much gas in place, as you really increase repeatability, I mean, the repetitiveness, you learn and learn and learn, you're always learning. Even in the Barnett, some of those last few wells in the Barnett that we -- that -- that we did so well on, we're learning stuff from those that we're applying even today.

Again, I think -- when we say we've got to make the Marcellus real, that's part of this whole process that we're on. We see this every day and that's why, again, we're pretty confident in terms of when we look at our valuation and we look at our ability to -- the exit rates and some of the things that Jeff has put before you, it's because -- we're not doing it because we hope it happens, we're seeing it happen real time here. And we're taking that and trying to project it forward and give you all the clearest view we can without -- without giving you too much of the treasure map that we think is just so important to keep confidential until the appropriate time.

All right, guys. Thanks for the color.

Thank you. Our next question comes from the line of Leo Mariani with RBC Capital Markets. Please proceed with your question.

Good afternoon here, guys. You guys commented about reducing your drilling times with some of these new fit for purpose rigs. Can you kind of quantify that at all in terms of how long it's going to take you to drill and complete a well now in the Marcellus?

Like you said, I mentioned about 10 things or so that we're doing differently and we are sort of doing those all in conjunction. And we're -- and I can talk about times per well. I think to me a more relevant statistic is what's it going cost. And I am telling you in this quarter I think we will get to -- we will reach $3.5 million per well for development well. So that's why I feel pretty good when I say we are going to spend $3.5 million to get 3.5 b's. I think those are reasonable numbers because I think we'll get there on development wells in the southwest this quarter and I think for the wells we have drilled so far, 3.5 b's is right down the middle of the strike zone. I could talk about days on wells and what kind of bits we use and I know everybody wants to know how long our laterals are and will we pump and which size mesh sand and -- but those -- I think that -- all I can tell you is I'm comfortable that we're -- that we'll hit those numbers that we're saying. I feel very good about the numbers we're putting out.

Okay. With respect to [Adell]'s comment about asset sales, can you give us kind of an order of magnitude about some of the sales. After Furman are we talking $100 million, $500 million, is there any kind of range you can give us about approximately how much capital is to come in from asset sales?

Leo, that's a good question and I appreciate you bringing that up, because I want to make sure I don't -- I don't give anything, any -- give anything that might not be -- give something that might be a little bit confusing. We've got Furman, it's producing about 16 million a day. I think you could use pretty traditional metrics and come up with a value there. The -- the other -- the other -- the other properties are relatively small. They are a couple of properties that are worth $15 million, $20 million, $30 million each. So it is hard to -- one, those small -- so, those small property sales you got, in most cases you got some smaller companies that have really very limited access to capital, so those things you never know if they're going to close, but they're relatively small. I would think both of those together anywhere from $20 million to $50 million probably, because one is I don't -- there's a chance we won't get them both done. So those are relatively small in compared to Furman.

Okay. Question about some of the other emerging shales you talked about in Appalachia. Obviously there is some other horizons out there. Is anything scheduled to get tested this year by you folks?

It most likely will be early next year when we drill those horizons, but they certainly look interesting. It's more than just a concept. With the exception of the Utica, all of the other shales are above the Marcellus. So as we drill through to Marcellus, you're drilling through the Berquette, Genesee, Middlesex, Rinestreet interval. So we have seen those on logs. We have show data and log data and in some cases core data that indicate that there are certain areas. Again, sort of like the Marcellus, people wave their arms over the whole play, you've got to be in the right spots. It's going to be like the Barnett or Fayetteville or Woodford. There is going to be, I think, key spots you'll want to be in and other spots you don't. But on our -- on our existing acreage the good news is we don't have to pick it up, we have very significant upside in those other horizons on our acreage and it's more than just upside. Like I said, we've got a number of wells that have drilled through the interval.

To be honest, to be completely transparent, that -- we did have some of those projects, those science projects we were going to do this year, but, again, it just comes down to capital and allocating capital. Those are the things that, quite frankly, we cut. We're just going to have to see higher gas prices and -- before we can -- before we'll get to that. Again, I think, that's what all the companies are doing (inaudible) in this environment., just -- those are the first things that get wacked. Those kind of projects in this environment, those are the first things that get whacked. Bill Zagorski and the technical team up in Appalachia are screaming about trying to do those things, but they understand that it's just going to take some time and we'll get to them eventually. And hopefully we'll get -- we'll kick off some of those early next year and peel back that onion and see what happens.

Okay. Just kind of final question on CapEx. Are you guys still targeting $700 million here in 2009 and does that $700 million include the $72 million you spent on acreage in the first quarter?

Yes, our CapEx budget is $700 million and of that we had $100 million allocated to land.. So we've spent $72 million of the $100 million in the first quarter. Actually we've spent in the first half of the first quarter. They were very efficient. So, yes, we're still at $700 million and our acreage budget is still at $100 million. I guess our Baltimore land people were playing a lot of golf this summer, but -- and I'm teasing. They'll have plenty to do. But, no, we're going to be -- we are going to be really, really disciplined. We're going to stick to our knitting. And like all of us, we're going to -- we are going to, yes, over the next month or two, just -- quarter or two to see -- to see how gas prices there and the rest of the stuff. We'll just -- we're going to be disciplined, but we'll stay flexible as well. So we'll getting all the proceeds in the second quarter. So again, it's just -- it is the timing and all that and feeling comfortable. We're going to stick with the $700 million and $100 million on terms of the acreage and what not.

Okay, thanks a lot, guys.

Thanks, Leo.

Thank you. We're now nearing the end of today's conference. I would like to go to Biju Perincheril of Jefferies & Co for our final question.

Hi, thanks. Good afternoon, guys. John, 900,000 acres is years and years of development and you hear a lot of talk about majors and international companies want to increase their exposure to shale plays in the US. Any thoughts along those lines maybe farming out or forming JVs with part of your acreage?

Well, when our friends in Oklahoma City did the deal with the Norwegians, obviously that got everybody, not so much us, but it got, I think, a lot of the bigger companies thinking about that and we have actually entertained those calls and met with them, just like we would anything else and discussed it with them. And we've kind of gone through it and everything else. There's a couple of things I will say about it. I think in general our strategy at Range is, and I am going to be general and I will come down from 50,000 feet down lower, but I think our strategy at Range and we thought about this a long time, we've talked amongst ourselves and ran numbers and really gave it a lot of thought, our theory in life is what we want to do is own as much as our highest quality asset as we can and over time divest of the more mature lower quality assets to help fund that. So if you agree with that strategy, then what our -- what our actions should be is not to do a JV but try to take capital out of these other projects by selling assets and using the cash flow and funding it back into these project. And it is also -- so that kind of the overall strategy.

The other thing is I just simply think it's too early in the play to get what I think is going to be fair value out of those joint ventures. I think, obviously, the guys, the bigger guys want to get it relatively cheap and we think, given the numbers and the wells we've drilled, we're -- we just -- we would command a much higher price, even if we wanted to do it. So to me it's too early in the play to do it. And the other thing is we want to focus Range at getting more of the play, not less of the play. So I think that's our strategy going forward. And -- and again, the key -- the key which is different than the other plays is and especially because of Range, because we were in there buying acreage at $50 to $100 an acre back in 2004, 2005, is that we have very few drilling commitments, a lot of our leases are five and ten-year leases with no drilling commitments with an age royalty. I think our average cost per ache is just $500. So we -- there's nothing that's pressuring us to have to drill it up now or tomorrow, other than just trying to add NAV for our shareholders. So, again, we will revisit that from time to time.

We looked at what Southwestern did in the Fayetteville, that once they had a really good idea and had defined the play, what they did is then they high graded their acres and they sold some acreage off. But still, we're -- we're -- we are a year or two away, or at least several years away from getting to the same place when Southwestern did that, that we need to consider doing that in the Mar -- in the Marcellus. We're just -- and the other thing is, it's so much bigger than the rest of the plays that this just needs to be -- it's going to take a little longer to develop it out and see where the good spots and the poor spots are. So I think all that -- all that -- I think it's a great [cash], Biju, and I think clearly over time we'll -- we'll consider all those things and we'll take the appropriate action. We just need more information and we need -- and the only way we're going to get that is us and the other companies just need to drill more wells. And as it becomes more defined, then we'll take action as we see appropriate.

Okay, that's fair enough. Thank you.

Thank you. This concludes our question-and-answer session. I would now like to turn it back to Mr. Pinkerton for any closing remarks.

Well, again, we appreciate all the Range shareholders for your continued support of the Company. We're excited about we've got and what we've had. I think you can see that and feel that from Jeff and his presentation. And it's really an exciting place to be in terms of to think of a Company that's our size that could be involved with one of the largest gas fields in the US is really, really exciting and we feel privileged. We're going to work our tails off. And again, our goal is really simple, we want to make it real for the existing shareholders of Range and we're all fully invested and we're really working in trying to make that real for the Range shareholders and with that we'll sign off and we'll see you next quarter. Thank you very much.

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