Range Resources Corp. (NYSE:RRC)
Q1 2009 Earnings Call
April 29, 2009; 1:00 pm ET
John Pinkerton - Chairman and Chief Executive Officer
Roger Manny -Executive Vice President and Chief Financial Officer
Jeff Ventura - President and Chief Operating Officer
Rodney Waller - Senior Vice President & Chief Compliance Officer
Rehan Rashid - FBR Capital Markets
Tom Gardner - Simmons & Company
Ron Mills - Johnson Rice
Leo Mariani - RBC Capital Markets
Biju Perincheril - Jefferies & Company
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 speaker’s 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 2009 with record production beating the consensus numbers and clearly continuing to execute our business plan for 2009 given the volatility in the commodity market. The first quarter marked our 25 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 on 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 own the home page of the website we would invite to you 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 the primary 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 11 and 12. Calyon Energy Forum in New York on May 13, the UBS oil and gas conference on May 19 and the Deutsche Bank energy conference in Miami on May 28. Our annual stockholder meeting is being held in Fort Worth on May 20. 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 25 consecutive quarter of sequential production growth.
The driver for that 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 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 inline with expectations. Unit operating costs for example came in at $0.93 per mcfe, well below last year. In regards to our emerging plays, in particular the Marcellus Shale play, we made significant head way 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 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 lowers 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 total $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 ‘09 was $158 million, 34% below the first quarter ’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 ‘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 a $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 2,000% from $2 million in the first quarter ‘08 to $33 million in ‘09. Due to $138 million non-cash mark-to-market hedging loss in last year’s number, versus a $31 million non-cash mark-to-market hedging gain in 2009.
Quarterly earnings calculated using analyst consensus methodology for the first quarter these years 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 margin.
Turning to the expense categories for first quarter ‘09 we see that the trend toward lower cost first visible at range in the 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 ‘08. Since then, we have seen this cost decline to $1 in the third quarter of ’08 and $0.94 in the fourth quarter last year.
As John mentioned, cash direct unit operating costs were $0.93 in the first quarter ‘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 for mcfe were 46% lower than last year’s first quarter, production taxes total $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 ‘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 first quarter fourth quarter. Exploration expenses for the first quarter of ’09 excluding non-cash stock comp expense was $12.3 million $3.2 million lower than first quarter of last year, mostly due to lower dry hole costs.
We anticipate that quarterly ex exploration expense, including non-cash compensation will approximate $15 million to $18 million per quarter the rest of the year depending, of course, on 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 last year and 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 non-cash expense was embedded in the DD&A expense line item. We’ve taken a $19.6 million expense to unproved properties in the first quarter ‘09. That compares to $1.4 million in the first quarter ‘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. 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 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 or not an unproved property becomes impaired are the acreage expiration date, the terms of the lease, the willingness of the mineral loner 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 spending is budget, oil and gas prices, cost to drill, complete and operate the area and the ability to sell or farm out 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 abandon expense and as you know, a lot has been happening in our industry over the past few quarters. Overtime, 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 on our future quarterly non-cash 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%. 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 nope and the legislative process is just getting started what.
We do know at range, is that we have a $159 million NOL carry forward and approximately $600 million in capitalized intangible drilling costs 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 for gas production hedged at a floor price of $7.42 per Mmbtu. The hedges are spread across a group of 12 high quality counterparties, ten of which are lenders 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 and P break even cost report published by Banc of America Securities reveals that range again has the second lowest break even 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 31, 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 have belief that our total volume capacity remains well in excess of our current $1.5 billion borrowing base. We have pressure tested the volume base at various prices and believe that even in a continued low price environment, we have sufficient liquidity to meet our needs.
Second, measures will note bank debt increased by $114 million during the quarter, reflecting front loading of some of the 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 cycle.
So we expect to bring 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 a company by lower unit operating cost. The quarter is also noteworthy for some of the things that we did not experience, such as significant reserve write-downs, 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 strength of record financial results. Range continues to deliver on our core mission. Steady reserve and production growth at low cost.
John, 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, 12% increase over the first quarter of 2008. This represents the highest quarterly production rate in the company eat history and the 25 consecutive quarter of sequential production growth.
Let’s now review our three key project. First, I’ll start with the Marcellus Shale, Appalachian Basin. With first gas process plant, which is a refrigeration plant came online last October and the capacity of that plant is 30 million per day.
The second gas processing plant the cryogenic plant came online in early April, which adds 30 million per day 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 net. We plan on accomplishing this by entering 2009 with three drilling rigs and exiting the year with a total of six drilling rigs. The fact that we believe we reach 80 million to 100 million per day net by running so few rigs, speaks to the excellent quality of the wells that we are drilling in anticipate drilling this year.
Although, it’s 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 etc., 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 we have drilling in the Marcellus, are a 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 expect that our team will continue to make significant headwind improving performance.
We believe the Marcellus Shale has excellent economics. We currently are estimating average reserves per well to be 3 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 in a $7 per NYMEX gas price, the rate of return is 75% and the F and 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 in cost, NYMEX could drop three and quarter per mcf and these wells would still have 20% rate of return. Our acreage position is nearly 900,000 net acres. The 900,000 net acreage equates to more than 15 to 22 Tcfe of net on 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 rate 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 and 9.1 cubic feet equivalent per day for their best 24 hour rates. For the best 30 days, the averaged 4.3, 7.2 and 7.6 million cube it feet 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 look 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’s good potential for all these horizons on our existing acreage in the Appalachian basin. The perspective areas of these unexploited shales targets largely occur within Range’s core Marcellus acreage positions thus allowing for stack pay opportunities and operational efficiencies in resource development.
Range owns a total of 2.7 million gross acres 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 in Virginia. There’s significant upside to all three horizons in Nora, CBM, tight gas sands and the Huron Shale. Range continues to drill successful CMB and tight gas sand wells in this field and has over 2,150 producing wells here.
F&D costs net to Range continue to be around $1 per mcf which is among the lowest in the country. In addition, these wells produce 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&D 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 in 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 two sales, which is very good.
The remaining two wells will be turned to sales soon. Rinestreet shales have potential of about 1.5 tcf of net gas reserves to range. The next idea we’re testing 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 Heron 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 un-book 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, after drilling and completing only 35 Marcellus Shale wells our best well 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 continue decline we’re currently producing about 125 million per day net from the play. On our core Barnett acreage are wells for average about 3 bcf and cost about 2.6 million. At $7
NYMEX this generates close to a 70% rate of return. At $5 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’ll use [inaudible]. In July of 2008 prices had significantly increased and we were paying 26.40 per foot. For July of 2009, we’re projecting 14.50 per foot.
In the Marcellus, we are also seeing significant cost reductions both from decreasing service cost 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 Fuhrman, Conger, Eunice, course in the Range and complementary acquisitions.
Going forward, our growth primarily will come from the Marcellus and Nora in the core area of the Barnett. These are all relatively new editions 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’re among the best rate of return and lowest F&D costs projects in the U.S. I believe that the Marcellus is the best project in the country, particularly when you couple that with the large reserve up side that it has.
The F&D costs for the all three properties ranges from about $1 to $1.50 and LOEs from all three are low. It’s also important that two of our top three projects are in the Appalachian basin with the gas prices 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 BFAs 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, a top quartile cost structure or better, and in addition consistently building and highgrading 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 tenfold, 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 overtime, back to you John.
Thanks, Jeff. That was 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 the second quarter of 2009 we’re looking for production to average 420 million to 425 million a day. This midpoint represents an 11% increase year-over-year.
I should note that the second quarter production guidance assumes we sell Fuhrman, the Fuhrman-Mascho Field midway in the second quarter. Fuhrman is currently producing approximately 16 million a day net. We’re in the process of finalizing the Fuhrman 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 Fuhrman, we have a couple of smaller properties that we’re in discussion with potential buyers. All that being said, with the momentum from the existing drilling results that Jeff talked about, 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 had 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 relate to capital efficiency. In the past few years, we spent considerable capital in the Marcellus play without seeing any visible return.
Beginning the 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 to 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 a fewer rigs running, the rate of capital spending will decline throughout the remainder of the year.
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 an the Barnett, we have a number of other properties that had 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 Fuhrman 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 continue to result in lowering our cost structure and it will focus our technical teams on high return projects and will ultimately result in issuing less equity. As I’ve 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, disciplined 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 overtime.
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 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 it’s 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 in the wells of average 3 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 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, it could 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 represents 20 to 28 Tcf of future growth potential. This equal seven to ten times our existing proved reserves. While we are excited about the growth potential of Range, we are intently focused on delivering each and every quarter. The first quarter 2009 is a sign example of this commitment, by all the employees at Range.
With that, operator, let’s open the call for questions.
(Operator Instructions) your first question comes from Jeff Hayden - Rodman & Renshaw.
Jeff Hayden - Rodman & Renshaw
Couple of quick questions, just curious about the, your Marcellus acreage position, you guys have kind of assumed about 900,000 for awhile, yet you’ve continued to add some acreage. Just curious has there been some acreage you’ve been weighing out of the core fairway as you continue to add or are you kind of staying conservative with the 900, we should really think entire than that?
We obviously, just to step back and we own 1.4 million net acres in the outline of the Marcellus, as you’ve pointed out, we’ve kind of, quote, high graded about 900,000 of that. We continue to add acreage. 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’re letting go or we’re selling to third parties or farming out to other operators.
All that being said, not trying to decoy, 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 that continued to drive up production along what we’re doing.
The acreage we’re buying and I want to stress this, the acreage we’re buying; as 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.
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 price is coming down. We’re getting it a fair amount cheaper.
Let me just add to that a little bit, when we talk about the roughly 900,000 about 550,000 was 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 and just in terms of what’s been both de-risked of course you’d like to see a 1000 wells there and 10,000 wells and in time I think you’ll see that, but the risk clearly is coming down and the potential of the wells looks excellent.
Jeff Hayden - Rodman & Renshaw
Just one other real quick one, on the two recent wells you guys reported, can you give us any color on lateral length, number of frac stages, etc that you use on those?
Yes, I mean, so far we’ve not given out real specifics. We have set in general; the designs are similar to what you see in the Barnett, in terms of lateral length in number of stages, but for a little while longer I think we’ll hold on to that.
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 IP, but wells that hang in there 30 days, 60 days. Our oldest horizontal well has been online and really almost two years. When we plot those wells versus the Barnett wells and we’re active in the Barnett, of course active in the Marcellus, they plot very favorably. So, real excited with what we have in and where we’re at this point in time.
Your next question comes from Rehan Rashid - FBR Capital Markets.
Rehan Rashid - FBR Capital Markets
Jeff, 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.
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, its true in the Woodford, its truly conventional plays, it’s truly onshore and offshore, it’s similar.
All in all, I’m very excited. I would like to say, 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 the large area.
I haven’t measured it recently, but I’ll bet some of our wells are as far as 40 miles apart, which is pretty far and 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 well. I complimented one of my bother from Cabot who used to work with Tenneco. They are doing a great job up there. The Northeast is going to have some good areas.
We’ve got 350,000 acres up there. We’ve drilled some good wells like Tuolumne County. So, there’s going to be winners and losers in the play, good area and bad areas, but clearly all of those companies that I mentioned have drilled number of excellent wells.
Rehan Rashid - FBR Capital Markets
Maybe I’m not ready to share it yet, so I’ll give you an easy out there, but what will it take to give keeping in mind the results that you have? What will it take to go revisit the three$3 million to $4 million and 3 to 4 Bcf that seems conservative enough at this point?
I’m glad you asked that, Rehan, a lot of people ask that, there is been, you’ve 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 to 10 Bcf. They’re excellent wells.
I’m comfortable right now, when we talk about 550,000 acres, that’s a huge position, when we talk about 900,000 acres, that’s massive. Again, I’d just come back and lot of people challenge me on that and challenges 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, signing cost or buck 16. Now, they work down to $3 a gas, I’ll do that all day long.
I think long run on gas it’s going to be $6 to $8 in mcf. I don’t know if any other play in the U.S. 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 what it is. When you couple those results with the fact that we’re in the Appalachian basin, we are getting the premiums to NYMEX and the lot of royalties that we have, it’s hard to beat those economics.
Could they better? Absolutely, some of these high-end wells I’m talking about, they are much better than 3 to 4 Bcf. I’m not saying that those wells are B’s. I’m just saying when you think in terms of broad acreage positions I think that’s a reasonable number based on what 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 to 3.5 days probably 3.2 on average. So I’m really excited by where we are, but I understand when you are trying to go. I just think it’s early, it could happen, though.
Rehan Rashid - FBR Capital Markets
So you need what, another year before you revisit or?
Well, we look at it all the time, but I think I’d like to see a large 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’re at least through the end of the year.
So, probably end of the year, early next year when we finish year end reserves, 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 disapprove 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 more every time, but it’s still a very competitive play. Its one of the few places in the U.S. where people or rig count increasing rather than dropping. So that’s the reason.
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 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.
Your next question comes from Tom Gardner - Simmons & Company.
Tom Gardner - Simmons & Company
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 the shallow drilling has taken place in the Southwest part of the state. So, 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 big, high pressure wells and a big development. They do provide a good by to test wells and it’s kind of a starter kit to get started. Also that the, right of ways are already defined and you can go in there and just dig another ditch and throw the pipe in there and on down the road.
Then some of the biggest pipelines in the U.S. 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.
There tends to be, a more forest lands and more state lands up there, but all that being said, we’re working on some infrastructure from the Northeast as we speak. Cabot’s done a good job of getting their wells tied in and we’re not. So, like I’ve said all along, I think one of the misconceptions about the Marcellus play is a quote.
The infrastructure is going to take longer. I tend to disagree with that. When you think about infrastructure again, some of the biggest pipelines in the U.S. run right in the middle of this and so it’s really a midstream issue, just tying 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 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 live within 350 miles around the city of Pittsburgh. So, if you have natural gas, that’s where you want to sell it.
Tom Gardner - Simmons & Company
Given what you said, the proximity to major pipelines, it appears that the processing bottled, the natural gas processing it appears to be kind of the chief bottleneck in the area. Are you focusing your drilling on dry gas areas to circumvent that bottleneck?
Tom, I’d just point out, anything in the Northeast there is going to be dry, it doesn’t need to be processed. Even 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. So, we’ll have Barnett really the end of this year, early next year 200 million a day of take-away capacity. We are talking about exit rate for 2010 being double, what we end this year. So, we’ll be in the capacity even if it were wet gas only, it’s going to be double what we need. So, we going to be built a year ahead of time, but we’ll also be working on take away.
We have take away capacity in some of the dry areas in the southwest and by the end of next year we’ll have take away capacity in the northeast. We ramped up in the southwest first, one because we like the area a lot as where we’ve start, and two to we had success really almost from day one with our original rinse well there and we can ramp up quicker for the reason John said, so that’s why we’re doing.
We’ll continue to ramp up in the southwest, but we’ll start drilling in the northeast as well and by the end of 2010, we’ll have production from both areas.
There is some advantages and disadvantages of wet gas. One, the disadvantage you’ve got a processes it, but that in time solves itself because you build a gas processing plant just like we did. The good news though is that because you get very high BTU gas, the economics are better and so it’s the chicken or the egg, but we think overtime those will kind of solve themselves when you’re going done the road.
I’d add, even after processing in the wet gas area. The gas that we sell is still about roughly 1150 BCU and we get paid for the BCU, so you take NYMEX times 1.15, 15% up lift, which is very significant and then add the basin differential to that so.
Plus you get to share of the liquid that you get from the plant. So, there is a lot of benefit there when you’re running through your economics and you calculate the bottom line economics. All that stuff needs to be taken into account. The one thing, I’d also like to say is that, again I’ll compliment our friends over northwest is that in joint venture of them, 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, so I really compliment them. It also goes to the testament, the people they want us there. The regulators, they want it done right, which we believe it. They got a after it, the permits were given in a reasonable amount of time and we got after it may have happen.
Again, basically March of last year and six months later having that gas flowing is really wasn’t incredible feed. I don’t look at that as a bottleneck as much as I really think we did it in lightning speed, so to speak.
Tom Gardner - Simmons & Company
One last quick question here with regard to the Nora well. Did you do anything different to that well to achieve that record, right and…?
I think, one again I’ll complement Jerry Grantham and his team, they are the once that force and Steve Gross looks over in that division, but or guys in general ranges, we have good partnership with [Inaudible] they worked on the CBM or work in the tied gasoline in the Shale and of course they operate it once we drilled and completed.
Our guys have done a really good job, by targeting specific areas and completely the wells a little bit different, so it’s a combination. When you get a well that good, and remember that wells are about 3400 feet deeper feet roughly, those kinds of Raven cliff wells can range from 3,000 to 4,000 feet deep.
When you find wells like that, that average over $3 million a day for 30 days to sales we get excellent economics quick pay out, so Jerry and his team have drilled a number of great wells down. We talk about CBM lot that those tight gas sand wells are great down there. Obviously, that one is not too tight because it’s doing pretty good.
Tom Gardner - Simmons & Company
Can it be a 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 Berea, and Berea we’re looking at horizontal drilling because it covers more areas, but in between the tight gasoline and Berea, so in between about 2800 feet and 5,000 feet, we have a number of other horizons, like the Raven’s Cliff and Big Lime and there is other formations.
The Raven’s Cliff tends to be channel that runs through there. So, as we continue to drill our infield drill, we’ve encountered a good Raven’s Cliff area and we’re seeing some of that before. We haven’t an announced those other wells that was just interesting because the original development of that field 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 quality if wells with get poor, these wells are actually getting better, that’s said in the record, but the Raven’s Cliff, I don’t think a good horizontal target, its been a long answer to your question, but the Berea, I think is the Big Lime is and there is a number of other horizons there that I think will be.
Your next question comes from Ron Mills - Johnson Rice.
Ron Mills - Johnson Rice
Jeff, I think you started to touch on this activity in northeast Pennsylvania versus southwest Pennsylvania. It sounds like you’ll 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 are all predominantly going to be in the southwest and it’s really early. Next year, though you’ll see significant drilling in the northeast and if we look carefully at the development plan that 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, getting in our market and where we started. All those things are parts of the decision that cause us to time drilling in one area versus another.
But you’ll see as drilling up in the northeast next year, like said really are best vertical well to-date, it’s up there. So, the wells we’re drilling on the southwest, I’m excited about the potential in the northeast there are 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 pretty big position.
Ron Mills - Johnson Rice
Given the fact you have pretty nice interstate pipelines in that area, you mentioned it’s really just matter of gathering lines, but is that the biggest issue in northeast PA?
Yes and it’s just timing and laying out our development. Gas there is going to be drives roughly 1000 BCU. So, but the guys are in the process of acquiring the firm transportation. We already have [PEP’s] and we’ve got plans for gathering and we know exactly everyone start drilling. So, we’ve got a good plan in place. I’m excited about that, this year should be really exciting, and next year should be even more exciting.
Ron Mills - Johnson Rice
Roger, for you just from a hedging standpoint. I think you would mention 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’re 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 of gas. To me it’s pretty simple. We took six and a half years to increase the rig count, natural gas rig count of about 750 rigs to over 1600 rigs and it’s taken us seven months to eliminate that, plus go below that.
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 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 quite frankly, we do have some specific numbers and thoughts in mind, but we’ll keep those to ourselves a little bit.
Ron, I think you can go back. Again, not trying to, but you can go back and look at what we’ve done historically. It’s not going to be too much different from that.
Ron Mills - Johnson Rice
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 there was someone 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 continue to ramp up 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 is zero in on that, because I think you said a couple things that we need to clarify and get some clarity and to be completely transparent. As I mentioned, we are in the process of getting these asset sales, Chad Stephens and his team have done a traffic job, are in the process of getting these asset sales signed up and again, pretty soon we’ll give you some clarity on at least Furman and then the little ones we’ll probably talk about next quarter.
That is the thesis, at least in our view, that between our existing cash flow and those asset sales. We believe confidently 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 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 capital efficiency that Jeff talked about and the productivity we’re getting out of our big three projects, we’re not to need to ramp up capital ‘10 over 2009 much, again to get very solid growth and hit our business plan and continue to double the production, the 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 -- we’re actually probably a little conservative than some, but if prices do respond higher than what we think. I mean could I see as increasing capital marginally, but not a whole lot.
Again, I think 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 numbers of rigs and so we’re pretty excited about that.
Again it comes back to this whole capital efficiency issue. We can do more with less, because the FD&A and the well results have been so much better than what we hoped for and so, therefore this gives us more confidence that we can do more with less.
Let me add a little bit another example of efficiency. I was talking to the guy Ray Walker who heads up for Marcellus Shale division, right before the call and where we do a lot of pre-planning what do we want to do at first this year, next year and five and ten years out, and we were talking about it’s way early when the true numbers out, but roughly speaking we are talking about it. We doubled the number of wells in the Marcellus next year and as sensitivity.
Now that can rise how more rigs, do we need if we do that and Ray said, it depends how efficient we get. There is a chance and I’m not promising, it’s just antidotal, but you can see the cost really coming down. We may be able to drill double the wells with the similar number of rigs or maybe just a couple more. You don’t need to double the rigs to double the number our time on the well, cost per well, speed on a well is getting so much better with the way that we’re drilling.
So, it’s another efficiency I’m 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’re doing.
Well, I think a great example by Jeff is, what Southwest has done recently in the Fayetteville in terms of some of the progress they’ve made in terms of drilling efficiencies, quality of wells what not and that’s 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 the shale of well quality tends to get worse overtime after you hit kind of piece.
There must be interesting thing in the shale plays, because there’s so much gas in play as you really increase repeatability I mean, the repetitiveness you learnt and learnt and learn. You are always learned. Even in the Barnes, some of the last few wells in Barnes that we did so well on, we’re learning stuff from those that we’re applying even today.
So again, I think when we say we got to make the Marcellus real, that’s part of this whole process that we’re. 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 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 real time here, and we’re taking that and trying to project it forward and give you all the clearest view we can without giving you too much of the treasure map that we think is just so important to keep confidential until the appropriate time.
Your next question comes from Leo Mariani - RBC Capital Markets.
Leo Mariani - RBC Capital Markets
You guys commented about reducing your drilling time with some of these new fit for purpose rigs. Can you quantify that at all in terms of how long itfs going to take 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’re sort of doing those all conjunction. I can talk about times per well. I think to me in more relevant statistic, as what kind of costs. I’m telling you, in this quarter I think we’ll get too. We will reach $3.5 million per development well.
That’s why I feel pretty good when I say we’re going to spend $3.5 million to $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’re drill so far 3.5 B’s is right down the middle of the Strike Zone.
I can talk about days on wells and what kind of bits we use and I know everybody wants to how long our laterals are and where we pump and which size mesh sand, but all I can tell you as I’m comfortable that will hit those numbers that we’re saying. I feel very good about the numbers that we’re putting out.
Leo Mariani - RBC Capital Markets
With respect to comment about asset sales, can you give us an order of magnitude about some of the sales after Furman, are we talking $100 million bucks, $500 million bucks. Do you have any kind of ranging you can give us about approximately how much capitals that coming from asset sales?
Leo, that’s a good question and I appreciate you bringing that up. I want to make sure I don’t give anything that might not be, just something that might be a little bit confusing. We’ve got Furman producing about $16 million; you could use pretty traditional metrics and come up with a value there. The other properties are relatively small, couple of properties that are worth $15 million, $20 million, and $30 million each.
One, those small property sales 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 there’s a chance we won’t get them both done. Those are relatively small compared to Furman.
Leo Mariani - RBC Capital Markets
This question about some of the other emerging sales you talked about in Appalachia, obviously there is some other horizons out there. Anything scheduled to get tested this year by you folks?
It most likely would 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 Shale’s are above the Marcellus. So, as we drill through Marcellus, we’re drilling through the Burkett, Genesee, Middlesex, Rinestreet intervals.
So, we’ve seen those on logs, we have show data in mark data and some cases core date that indicate that there are certain area, 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 want to be and other spots you don’t, but on our existing acreage the good news is we don’t have to pick it up. We have very significant up side in those other horizon on our acreage and it’s more than just up side like we said, we’ve got a number of wells that are drilled through the intervals.
To be completely transparent, we did have some of 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 and we just going to have to see higher gas prices and before we get to that.
Again, I think that’s where all the companies are doing. As the CEO as I talk to those, kind of projects in this environment, those are the first things that get whacked and those are [Inaudible] in the technical team up in Appalachia are screaming about trying to do those things, but they understand it just going to take sometime and we’ll get to them eventually and hopefully we’ll kick off some of those early next year and peel back that onion and see what happens.
Leo Mariani - RBC Capital Markets
Just final question on CapEx, you guys still targeting $700 million here in 2009 and does that $700 million include the $72 million 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 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 a lot of our land people were playing a lot of golf this summer, but I’m teasing they’ll have plenty to do, but we are going to be really, really disciplined. We are going to stick to our knitting and like all of us we are going to over the next month or tow or quarter or two to see how gas prices are doing compared to the rest of the stuff.
We’re going to be disciplined, but we’ll stay flexible as well. So, we’ll get all the proceeds in the second quarter. So again, it’s the timing of all that and feeling comfortable. We’re going to stick with this $700 million and $100 million in terms of the acreage and whatnot.
Your final question comes from Biju Perincheril - Jefferies & Company.
Biju Perincheril - Jefferies & Company
Good afternoon guys. John, 900,000 acres years and years of development and you hear a lot of talk about mergers and international companies want to use their exposure to Shale Plays from the U.S. Any thoughts along those lines maybe farming out or JV part of your acreage?
Well, when our friends in Oklahoma City did the deal with the Norwegians, obviously that got everybody, not so much of 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.
We’ve kind of gone through it and everything else. There are a couple of things I’ll say about it. I think in general, our strategy at range and I want going to be general to be drilling and I’ll comedown from 50,000 feet down a well, but I think our strategy range and we thought about this a long time, we talked amongst ourselves and ran numbers and really gave 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 overtime, divest of the more mature lower quality assets to help fund that. So, if you agree with that strategy, then 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 projects. So, that is kind of the overall strategy
The other thick 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 bigger guys want to get it relatively cheap and we think, given the numbers and the wells we’ve drilled, 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 and not less of the play. So, I think that’s our strategy going forward and again the key, which is different than the other plays is and especially because of range because we were in there buying acreage $50 million to $100 million 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 acres is $500 bucks.
So, there’s nothing that’s pressuring us to have 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 done the Fayetteville, but once they had a really good idea and had defined the play what they did is then they high-graded their acreage and they sold some acreage off, but still we are a year or two away, at least several years away from getting to the same place when Southwestern did that we need to consider doing that in the Marcellus.
The other thing is it’s so that much bigger than the rest of plays, it’s going to take a little long to develop it out and see where the good spots and the poor spots are. So I think it’s a great question, Biju and I think clearly overtime we’ll consider all those things and we’ll take the appropriate action.
We just need more information, and the only way we are 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.
Thank you. This concludes our question-and-answer session. I would now like to turn it back to Mr. Pinkerton for any closing remarks.
We appreciate all the range shareholders, for your continued support of the company. We’re excited about what we’ve got and what we’ve had. I think you can see that and feel that from Jeff and his presentation. It’s really exciting place to be to think of a company that’s our size that could be involved with one of the largest gas fields in the U.S. It’s really, really exciting and we feel privileged and going to work out tails off.
Again, our goal is really simple. We want to make it real for the existing shareholders at range and we’re all fully invested and we are really working and trying to make that real for the range shareholders. With that we’ll sign-off and we’ll see you next quarter. Thank you very much.
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