山脈資源 (RRC) 2008 Q2 法說會逐字稿

Greetings ladies and gentlemen and welcome to the Range Resources second quarter 2008 earning conference call. This call is being recorded. (OPERATOR INSTRUCTIONS). Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which can 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. David Amend, Investor Relations Manager of Range Resources. Thank you. Please go ahead, sir.

Thank you operator. Good afternoon and welcome. Range reported results for the second quarter of 2008, posting our 22nd consecutive quarter of sequential production growth even during a challenging quarter. We've posted on our website supplemental tables to assist you in understanding many of the numbers in the press release. In the press release, we have furnished some non-GAAP statements, which allow you to compare our results through historical numbers, which complete the Gulf of Mexico operations that we sold during 2007 and in table five of the supplemental tables we have presented a summary of the numbers which correspond to the analyst models taking out the non-cash items.

On the call with me today, are John Pinkerton, Chairman and Chief Executive Officer, Jeff Ventura, President and Chief Operating Officer, and Roger Manny, 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 SEC this morning. It is available on the home page of our website or you can access it using the SECs EDGAR system. In addition, we have posted on our web site supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you detailed information on our current hedge position by quarter. We've also updated our investor presentation to reflect information that will be discussed on today's call and it will be available on our website tomorrow.

Second we will be participating in several conferences in August and September. Check our website for a complete listing. We will be at the Intercom Energy Conference in Denver on August 10 and the Lehman CEO Energy Conference in New York City on September 2nd. Now, let me turn the call over to John.

Thanks, David. Rodney Waller, as many of you know isn't with us today due to an illness in his family but he'll be back with us shortly. Before Roger reviews the second quarter results, I'll review the key accomplishments so far this year. On the year-over-year basis second quarter production rose 22%, beating the high end of our guidance by 6 million. As David mentioned, this marks the 22nd consecutive quarter sequential production growth. The driver of the higher than expected production was exceptional performance by really all of our divisions. As you recall, I mentioned that in the first quarter it was one of those rare quarters where everything went right and essentially nothing went wrong.

For the second quarter, we were not as fortunate in that we had a number of issues we had to overcome. Most significantly we had on average 18.5 million a day of Barnett production shut-in due to third-party pipeline curtailments. To offset the shut-in production our operating teams reshuffled the drilling schedule, performed numerous work overs, fast forwarded well turns and pulled many rabbits out of the hat, sort to speak. I am extremely proud of their performance and I want to publicly thank them for extending our production growth to 22 consecutive quarters.

On the drilling program we remain on schedule throughout the quarter and we have 180 wells. We continue to be extremely pleased with the drilling results, which Jeff will talk a number of the wells. We are doing fantastic rate of return and currently we have 30 rigs running. The 22% increase in production coupled with the 17% increase in realized prices drove up cash flow $221 million. This is $64 million or 41% higher than the second quarter of last year, since it was a terrific quarter. By posting record production volume in the benefit of strong commodity prices, clearly, we set the stage for another record year for Range. Based on - - because of the shut-in production and the extra cost we incurred to overcome the shut-in, coupled with the continued ramp up in personnel in our Marcellus Shale play in Appalachian, our unit costs were higher versus the prior year. Once we get to Barnett production back on, which should happen sometime by the end of the year in the Marcellus gas, we are confident our per unit cost will drop back down to historical levels.

With regard to the merging plays, a lot of head waive was made in the second quarter, as we mentioned in the press release and as Jeff is going to talk about, we drilled some terrific wells. We continue to expand our acreage positions and our infrastructure projects are on track and look really good. In addition, we continue to build out our technical teams, especially with regard to the Marcellus and given us some great advantage and the quality of the wells speak to that. At the end of the day, I couldn't be more pleased with what we have accomplished so far in the year. It's a real testimony to everybody at Range. With that Roger why don't you review the financial results.

Thank you John. The second quarter of 2008, proved to be true to its name as we recorded the second highest quarterly oil and gas sale, second highest quarterly EBITDAX and second highest quarterly cash flow in our history. Oil and Gas sales including cash settle derivatives, were 313 million, 42% higher than the second quarter of last year.

EBITDAX for the quarter, came at 244 million, 41% higher than the second quarter of '07 and cash flow was $221 million, also 41% higher than last year's second quarter. The strong quarterly performance was driven by 22% year-over-year quarterly production increase and 17% higher year-over-year quarterly average oil and gas price. Interestingly, the second quarter of this year unfolded just like the second quarter of last year. The first quarter of '08 and '07, both set new record quarterly highs for oil and gas revenues, EBITDAX and cash flow. In both years this first record quarter was followed by a second quarter of second best results. So while production continues to head up into the right, the second quarter 2008 realized oil and gas price per mcfe of $9.03 was 5.5% below the $9.55 price realized in the first quarter of this year. Now second quarter 2008 cash margins was $6.34 per mcfe - - $6.37 per mcfe, 17% higher than the second quarter of '07.

As for net income, oil and gas companies that hedge their production to protect cash flow had a tough second quarter in '08 and Range was no exception. Net income was impacted by several non-cash expenses. First, a non-cash 164 million mark-to-market on unrealized oil and gas hedges. Second, a non-cash 7.5 million mark-to-market expense due to the increase in Ranges stock price and third a non-cash 5.3 million reduction in unproved leasehold value.

The 2008 second quarter GAAP net loss was 35 million compared to prior year second quarter GAAP net income of 64 million. Quarterly earnings calculated as analysts do were $75 million or $0.48 per diluted share, compared to the analyst estimate of $0.54 per share and the difference was 5.3 million in non-cash acreage expiration, which were included in DD&A this quarter. Because of the mark-to-market forward price curve for oil and gas have declined since the quarter end, for illustrative purposes, we remark-to-market our quarter-end hedge position using closing oil and gas prices from last night, July 23. We discovered that had oil and gas prices at the end of the quarter been the same as they were from yesterday, the non-cash 164 million pre-tax mark-to-market loss would have been completely eliminated. Now cash flow per diluted share this quarter was $1.41, matching the analyst consensus. As always, please visit the Range Resources website for full reconciliation of all these non-GAAP measures including cash flow, EBITDAX, adjusted net income and cash margins.

Cash direct operating cost for the second quarter of '08 was $1.05 per mcfe compared to $0.96 in the first quarter of this year and $0.86 last year. There are several unusual items embedded in this higher cost figure, the largest of which, is $0.05 per mcfe associated with shut-in Barnett gas production. Productive, yet shut-in wells still require maintenance and incur expense even though they are not producing. Also work over expense for the second quarter was $0.10 per mcfe and that is up $0.06 from the first quarter and $0.07 from last year. Adjusting for these items, cash direct operating cost would have been $0.96 consistent with our mid to high $0.90 range cost guidance previously provided.

Looking forward we expect cash direct operating expense to run in the high $0.90 range for the rest of the year. General and administrative expense, adjusted for non-cash stock comp expense was $0.49 per mcfe for the second quarter, up from the $0.44 figure in the second quarter of last year. G&A expense, direct operating expense suffered in the second quarter due to higher payroll cost and the production curtailment that John mentioned. To illustrate the point, we now have over 70 full-time professionals on the Marcellus team on the ground in Appalachian, building a terrific acreage position, drilling excellent wells, but producing very little gas until the infrastructure is completed. This is a temporary unit cost increase that reflect the reality of developing a world-class resource from scratch as opposed to buying existing production. Placed in the proper perspective, trading a nickel in short-term G&A expense for finding, development and acquisition cost that are dollars below industry average is a good trade for the shareholders. Cash G&A expense will likely remain in the high $0.40 per mcfe for the rest of the year.

Second quarter interest expense was $0.69 per mcfe, flat with the first quarter this year and $0.07 higher than second quarter of last year. And as we continued to increase our debt level and periodically refinance our short-term floating rate bank debt with fixed rate ten year subordinated notes, our interest expense has increased. So expect interest expense per mcfe to run in the low to mid $0.70 for the rest of '08.

Expiration expense for the second quarter of '08 excluding non-cash compensation was 18 million. That is 8 million higher than the second quarter of last year mostly due to 6 million increase in seismic expense. It's been a while since I mentioned it, but please remember that Range does not capitalize any of its exploratory or developmental seismic expenses. So the ebb and flow of our seismic activity, that timing flows straight through to the bottom line. We anticipate the quarterly expiration expense including non-cash comp will approximate 20 to $22 million per quarter the rest of the year. Depends, of course, on our ongoing drilling success and timing of seismic purchases.

Depreciation, depletion, and amortization per mcfe for the second quarter of '08 was $2.24 compared to $1.81 in the second quarter of last year. Of this $2.24 figure $1.95 represents depletion expense the same as last quarter while $0.14 is attributable to depreciation and accretion expense and as previously mentioned, $0.15 or 5.3 million came from leasehold expirations. Our core depletion rate should remain in the $1.95 per mcfe range for the rest of the year. Reductions in unproved acreage values are more difficult to predict; however, we do expect to incur $5 to $8 million per quarter in unproved acreage value reduction, primarily from expirations, going forward as we continue to drill in high grade our acreage portfolio. So DD&A, with the ongoing acreage expirations, should run $2.24 to $2.27 per mcfe for the remainder of the year.

For the six month year-to-date '08 period, oil and gas sales plus settled derivatives totaled $635 million, up 42% from the $449 million during the first six months of '07. EBITDAX for the first six months of '08 was $590(inaudible - background noise) , up 44% from last year and cash flow increased to $462 million, 45% higher in '08 compare to the $318 figure from last year. The balance sheet was substantially strengthened during the second quarter through two transactions, first, we issued 4.4 million new common shares generating $282 million in proceeds, which was used to repay bank debt incurred earlier in the year to fund Barnett Shale acquisitions. Second, we refinanced part of our short-term bank debt, 250 million of 7.25% ten year subordinated notes. With the issuance of equity, our debt-to-cap ratio was reduced back below our 40% target, but rose to 43% at the end of the quarter due to the 279 million of negative other comprehensive income that we recorded due to our hedge position. Range ended the quarter with nearly 800 million in unused committed bank facility funding and we had a 1.3 million in unused bank borrowing base capacity. We have our strongest balance sheet in recent memory.

As John mentioned at the start of the call, the first quarter of '08, was one of those rare quarters when virtually everything went right, nothing went wrong and every part of the Range organization exceeded their target. The second quarter '08 was not this type of quarter. At production curtailment in the Barnett and the need to right size the Marcellus team before infrastructure completion has temporarily increased our unit cost structure (inaudible - background noise). But this should not obscure the fact that top line year-over-year quarterly oil and gas revenue grow is 42% and we have posted 41% year-over-year quarterly EBITDAX and cash flow growth.

Lastly, the balance sheet was substantially improved during the quarter and Range has more than enough liquidity to execute its operating strategy going forward. With that John I'll turn it back to

Thanks Roger. That was an excellent update. I will turn the call over to Jeff Ventura to review our expiration and development activity. Jeff?

Thanks John. I'll begin by reviewing production. For the second quarter production average 381 million per day, a 22% increase over the second quarter 2007 and a 3% increase over the first quarter of 2008. This represents a highest quarterly production rate in the company history and the 22nd consecutive quarter of sequential production growth.

Let's now review three of our key projects. First, I'll start with the Barnett Shale in the Fort Worth Basin. During the second quarter, we experienced curtailments in the Barnett and they were significant. At times we had well over 30 million per day shut-in. The good news is that despite that we were still able to beat our production target. We were able to do that because of the strength of our portfolio of opportunities and more importantly because we have a team that consistently rises to the occasion and delivers. The curtailment situation in the Barnett is improving with the start up of new gathering/ transmission line with the takeaway capacity of 300 million per day scheduled for later in the third quarter. Another line, with additional take away capacity in excess of 700 million per day is scheduled to start up in the fourth quarter.

Currently we have six rigs running in the Barnett. Net production is about 90 million per day, today, in addition to that we currently have about 22 million per day shut-in. Despite the shut-Ins we are projecting 19% production growth for Range for 2008. Range currently has 109,000 net acres in the Barnett Shale play, 42,000 net acres on in Tyrant, Johnson, Benton, eastern Parker, eastern Hood, northwest Ellis and southwest Ellis counties. This is the proven part of the play and we have over 700 locations to drill on these areas. That assumes 500 foot spacing which equates to about 40 acres per well. It assumes 15% of the acreage is developed on 250 foot spacing, which may prove to be conservative. This represents 1.2 tcf of net unrisk upside - - unbooked upside in the Barnett. We also have 51,000 net acres in Hill and southwestern Ellis counties, which represents an additional 0.8 tcf of upside. Combined this is about 2 tcf, which by itself can almost double the size of Range. A recent highlight of our Barnett drilling program are our last four wells in the Carter Industrial Park. They tested at a combine rate of 33 million per day gross or 25 net. That's an average of 8 million per day, per well, which is outstanding. We also made significant progress reducing our well cost in eastern Hood county. Our last 4 wells averaged ten days, from spud the rig release. The cost of casing point was about 500,000 and the total completed well cost was 1.6 million. These wells averaged 2 bcfe per well so they have excellent F&D cost, well below a $1 and great rates toi return.

Our first well in northwestern Ellis county came on line at a rate of 2.6 million per day and also we previously announced a 5 million per day well in eastern Parker county. Our second southwest Ellis county well was like the first one. It had good thickness and gas in place but produced subpart rate of 1.3 million per day. Our Hill county drilling is similar, good thickness in gas in place but disappointing production rate for the initial wells. We still have experimentation to do and we are making progress. Our last well produced at an initial rate of 2.4 million per day. The other thing we have seen in Hill and Ellis county is that although the initial rates are lower the decline rates are lower than the core of the Barnett. If we can replicate our latest well we can generate good F&D and good rates of return. The key is our high quality team headed up by Mark Whitley, I'm optimistic they'll be able to solve the formula and unlock the gas. Another very impactful low risk project for us is our Nora area located in Virginia in the Appalachian Basin. This is another project that has the potential to double Range's reserve. There are significant upside to all three horizontal in Nora, coal bed methane type gas sands in the Huron Shale. Range continues to drill successful CBM and type gas sand wells in the field. F&D cost, net to Range continue to be around a dollar which is amongst the lowest in the country. In addition the wells produce very little water and have low lift cost. Given its location in the Appalachian Basin these wells receive premium to NYMEX. This is combination with low F&D and low LOE results in very good rates of return for these wells. Given the large number of wells to be drilled on current spacing and assuming successful down spacing, which it appears that it's happening, there are approximately 6,000 wells left to drill.

The latest development in Nora, is horizontal drilling in the Huron Shale. Our first well, which was completed in the fourth quarter last year came on line as initial rate of 1.1 million per day. It cost about 1.2 million to drill and complete although sit is till early, initial reserves are about bcf. Given our working interest in net revenue interest, and remembering that Range owns the minerals, our net find and development cost is about $1.07 per mcf. This year we expect to drill ten horizontal delineation wells across the 250,000 Nora block. We know that the Huron Shale has good thickness and gas content across the 250,000 acres because there are 107 producing vertical Huron Shale wells on this acreage. The purpose of the ten horizontals delineation wells is to verify that horizontal drilling is an effective way to economically develop these reserves. If the Huron wells are successful they will de-risk about 1. tcf of net gas reserves to Range by year end.

We recently just completed our first three horizontal shale wells in our 2008 program. Two of these wells are on line. One of the wells had initial rate of 1.2 million per rate. This well 3200 foot lateral and we completed 8 stages. The other well had drilling difficulties which resulted in 1719 feet of lateral. The well had a initial rate of 565 mcf per day. The difference in rate is proportional to the lateral length. So far I'm encourage with the Huron Shale potential in Nora field. Next project will be starting at Nora's horizontal development in the Brie Sandstone, which we believe has excellent potential on our acreage as well and the Brie is one of the existing type gas sands that we've been developing vertically for years and are excellent wells.

Another high impact opportunity for Range is on Marcellus Shale play in the northern part of the Appalachian Basin. Last week, we announced that we now have 1.4 million acres of Marcellus Shale acreage. We believe our acreage or high graded acreage now stands at 850,000 acres which equates to 15 to tcfe of net unrisk reserve potential. Of that, 10 to 15 tcfe located in the southwest part of the play with the remainder in the northeast. To date we have drilled and completed 22 horizontal Marcellus Shale wells and have additional three horizontal wells waiting on completion. In yesterday's release, we announced our last seven completions which had initial production rate that averaged 4.9 million per day. This compares to 4.1 million per day for the ten wells prior to that. Range also recently announced that these wells should cost $3 to $4 million in the development mode and we expect reserves to be 3 to 4 bcfe per well. That generates finding and development cost of $0.90 to $1.60 per mcfe. We've also announced an agreement with MarkWest to develop midstream infrastructure and also announced that to date we have secured front capacity on the pipelines of 150 million per day and our currently negotiating for additional capacity. In terms of water source and water disposal required to hydraulically fracture Marcellus wells, Range is making excellent progress in handling these requirements for our projects.

It interesting to note that Pennsylvania second only to Alaska in terms of water resource. We continue to work within the state regulation to secure these water sources and have made excellent progress. We also recently signed four agreements with existing regulatory approved water disposal facilities that should more than handle our water disposal requirements for the next several years. Our current focus is to begin development of our core areas, continue to delineate our acreage and aggressively add to our Marcellus lease hole in select areas.

We have three rigs running and we'll drill approximately 40 horizontal Marcellus Shale wells this year. 2008 will primarily be a year of delineation, acreage acquisition and building infrastructure. We expect significant volume growth will occur in 2009 and beyond. In addition to pursuing the Marcellus Shale we've also initiated studies on Utica Shale, Berquette, Genesse, and Limestreet Shales. There's good potential for all these horizons on our existing acreage in the Appalachian Basin. Range now owns 2.7 million gross, 2.3 million net acres of lease hold in Appalachian.

I'd like to switch gears and talk about the curtailments that we have in the second quarter and things we did to overcome them. Range had a strong portfolio of projects that we draw on when confronted with challenges and high quality team that consistently rises to the occasions.

For the second quarter, both the mid continent and Appalachian teams rose to the occasion. In the mid continent, the team drilled some very wells in the granite wash in the Texas Panhandle and also in the Watonga/Chickasha area. In particular, the granite wash is developing into a very nice opportunity for Range. Currently, it looks like we have an excess of 200 granite wash wells to drill in three different plays. Two are on the Texas Panhandle and one is in western Oklahoma. One is in a horizontal granite wash play on the southern part of our horse and ranch area. The granite wash target zone here is about 50 feet thick and wells are about 9300 feet true vertical depth. The wells come on line at about 2 to 3 million per day.

The other Texas Panhandle granite wash play is southeast of there, where the granite wash is over 600 feet thick, this is a vertical development. The wells are about 12,000 feet deep and come online at rates of 2.5 to more than 3 million per day.

In addition to achieving good drilling results, the mid continent team also cranked up the recompletion work over effort. The best one of the bunch was the recompletion to a Douglas zone in a well on [Corsson] Ranch. This recompletion cost about $400,000 and resulted in a strong well that came on line at a rate of 6.6 million per day and still producing at about that rate. The mid continent team also optimize the pumping at some of our oil wells in northern Oklahoma by changing out steel rods for fiberglass rods. This increase the oil production of our wells there.. The best result for an individual well resulted in a a gain of more than 100 barrels of oil per day. We are also optimized gas gathering there which increased production by more than a 1 million per day.

The Appalachian team also stepped up and helped the company to achieve our results. In particular, our team in Virginia did a great job of drilling some exceptional type gas wells. A particular note, as a big line well, at Nora that came on line at a rate of 2 million per day and still very strong producer. Prior to that, in noteworthy, is a [Ravensclip] well that they drilled that came on line at 2.4 million and also very strong producer.

In the northern part of the basin, the team drilled two exceptional [Beatman Town] wells that combined came on line at 2 million per day. There are numerous small projects across all of the divisions that when combined overcame the shut-in and resulting in beating our production target and posting 22nd consecutive quarter production growth. That did come with the cost however. If we were not have been curtailed and had to scramble to overcome, it would have lowered our LOE by about $0.06 per mcf for the quarter. Clearly, we would choose not to be curtailed. At this point in time though, we know that today we have 22 million cubic feet per day shut-in. By year end all that should be back on line. Although, we are experiencing curtailments during the third quarter we still produced 384 to 386 million feet equivalent per day and post our 23rd consecutive quarter of growth.

The fourth quarter should be 395 to 400 million cubic feet equivalent per day which is our 24th quarter of growth and 19% production growth for the year. 2009 should start out strong with the ramp-up for the Marcellus Shale production. We are targeting 30 million per day in the first quarter of 2009. To summarize, Range is in a great position. We have a proven reserve based of 2.2 tcfe, on top of that we have identified upside of between 20.5 to 22 or 28.2 tcfe, primarily in low risk coal bed methane, shale gas and tight gas sand plays. We have a great track record of converting that to value for our shareholders. Range is where we want it to be, a low cost producing with a lot a low risk built -in growth. In summary, we are in a terrific position to continue to build shareholder value on into the future. Back to you, John.

Thanks Jeff. Terrific update. Looking to the second half of '08, we see continued strong operating and financial results. As Jeff mentioned, for the third quarter we are looking for production to come in at approximately 384 to 386 million a day. That is 18% higher than the prior year. With higher production and strong process we again anticipate third quarter revenues, cash flow, and earnings will be substantially higher than the prior year period.

Looking into the fourth quarter we anticipate production to continue to increase and should be in the range of 395 to 400 million equivalence a day. Given what we know today, we anticipate that the shut-in production, Barnett production to come in by the end of the year, after the pipeline expansions are completed. I think the key point here is that we still currently anticipate reaching our 19% production growth target for the year despite the shut-in from the Barnett. So I think that is really good news.

Due to the higher volumes and the prices for the year, operations cash flow from operations we anticipate to increase by more than 30% over 2007. So as you can see, 2008 should be a tremendous year financially for Range and it's shareholders. While we focus on getting our wells drilled and hitting our quarterly production targets, we also continue to expand our drilling inventory and make exciting progress with our emerging plays. As you heard from Jeff, our technical teams have drilled some additional high rate wells in several different plays. With regards to the Marcellus play in particular, the 4.9 million average test rate for our most recent seven wells is extremely encouraging. Given our success and additional opportunities we have identified, we'll move quickly and aggressively. Our expanded Marcellus team, gives us the ability to be aggressive; however, we will maintain our discipline approach and financial regimen.

Important to our gas gathering and processing infrastructure projects in the Marcellus, we are making solid progress, they are right on track. We are right on track to begin ramping up our Marcellus production the first quarter of '09. We are on track to increase our Marcellus drilling activity in 2009 and beyond as we tie up additional drilling rigs as well as water infrastructure.

As Jeff mentioned we recently executed four additional agreements, regarding water source and disposal. These arrangements coupled with our existing arrangements will give us plenty of running room in terms of that part of our business. On the pipeline infrastructure side we made arrangements that provide for considerable take away capacity. So when you think about those, the way we look at it, the water and pipeline issues may limit some of the operators in the play, these issues shouldn't limit us given the actions that we have taken. So we feel really good about that.

For those of you that have been shareholders when we initiated the Marcellus play, your trust and patient is very close to paying off as we are right around the corner from seeing material production volumes and cash flow from this exciting play. There is no doubt in my mind that the Marcellus Shale play will be a key driver to the value of Range for many years to come.

In summary, looking at Range today we have the largest drilling inventory in our history, with over 11,000 projects. Our inventory together with our emerging plays, represents 21 to 28 tcf of future growth potential, this equates to 9 to 13 times our existing crude reserves. We are excited about the growth potential at Range and we are focused on delivering each and every quarter. The second quarter in particular, is a shining example of this commitment by all the employees at Range.

Prior to opening up the call to questions I would like to make one final comment. I want to assure all of our shareholders that we will maintain our sharp focus on per share value. As I mentioned, many times at Range we care about our stock price, not our market capitalization. Several acquisitions have recently been announced in which we participate in the bidding process. We lost out on those acquisitions because we were unwilling to undertake acquisitions that make us bigger but don't result in any higher per share value. No matter how much we like the property, we will not buy it unless it clearly increases our per share value. This disciplined approach is built on our confidence that we can continue to deliver double-digit growth at low cost for many years to come with our existing portfolio of properties. While we continue to seek acquisitions, we will do so only when we believe it benefits our existing shareholders by making their shares more valuable. With that operator, why don't we open up the call to questions.

Thank you, Mr. Pinkerton. (OPERATOR INSTRUCTIONS). Our first question comes from the line of Joe Allman with JPMorgan.

Good afternoon, everybody. John or Jeff does four agreements in the Marcellus Shale, those would give you water access and take care ever water disposal. How long does that last for and what are the geographic areas covered there?

Yes. If the agreements are both for water procurement and for water disposal, it will take care of itself for the next few years and of course along with that in parallel, we'll continue to pursue other ways and additional ways to optimize handling of water. But our team has done a great job there. We are looking at not drilling wells but we are looking the sources of water, uses of water, gathering system, pipelines, firm transportation, procuring drilling rigs and all the things that we need like John said to carry out our program for the next several years. We've got multiple areas we are looking at developing in those agreements will cover multiple areas. But as a lot of people know, we have great acreage position. When you add all of our wells, we have 100 wells across the Marcellus plus we have all the control points from all the Atlas wells that were drilled as well as others. So we have multiple areas we think from the perspective some of the drilling this time we drilled some really significant step wells along ways from each other. So we'll be developing a lot of areas. But as you are aware and most people are aware a lot of our development will come in the southwest first.

Got you. And then could you talk about any other regulatory or environmental issues that you need to confront in developing this play?

We are constantly working with all the agencies up there and we think we are going down all the paths we need to go down. At the end of the day it's not a great opportunity for Range. It's a great opportunity for the state of Pennsylvania. Just like the Barnett Shale here in the Fort Worth Basin has created close to 100,000 jobs. We have the potential to create more than that in Pennsylvania. It will be a great opportunity for job creation and great opportunity to bring a lot of industry for the land owners and mineral owners as well as a good deal for the country. It's natural gas. It's clean. It's a domestic fuel.

So we are talking to state and local people constantly and we think we are making and building good relationships and like all projects there may be bumps along the way but we think we are long ways down the road and importantly like we've talked about we are going to come on in a significant way in the first quarter. We expect production to reach 30 million per day in the first quarter. We expect to ramp up to eight rigs in 2008 and continue to drive volumes up in significant ways. We are securing more additional firm capacity beyond 130 million a day a well in excess of 130 million per day that we talk about. So 150 per day that we talked about. So we are excited about the project and just like in the Barnett the guys have done a great job with 6 rigs we drove production up in the Barnett close to 100 million a day and if you add the shut-in volume, we will get all those volumes back in line by the end of the year. We will be well over 120 million per day net, just running 6 rigs in a 2 year timeframe. So planning to going 8 rigs initially in the Marcellus but those are the things that we'll be fine-tuning, August, September, this Fall and toward the end of the year and early next year we'll continue to put out more updates in terms of the flight.

Got you and on that 30 million in the first quarter of '09, that's not an average rate. That is just a level that you'll reach during the quarter?

Yes. But I'm confident our guys will hit that and continue to drive it up.

And on the Barnett, do you expect to grow the Barnett between now and the time you get those pipeline issues resolved or it will be relatively flat? What areas are going to drive the production growth?

That is really important and one of the comments I wanted to get across on this call. And a lot of people that I talked to think, you have the Carter Industrial Park that is great but it's only 2,000 acres and not a lot of drilling and you have Hill and Ellis County. That is not true. We have a really significant position in the Barnett and like I said we have 42,000 acres and more than 700 wells on conservation spacing assumptions of 40 acres or better. They are right in the guts of the play. On our website, which David will update and it will be out tomorrow or no later than Monday, we are going to highlight some of the other areas. There will be slides showing what we are doing in eastern Parker, eastern Hood, southern Tyrant, southeast Tyrant, some more Johnson county drilling that have nothing to do with the expansion. So when you look at the curtailments the whole play isn't curtail. Really, all the curtailments we are experience today are just in the Carter Industrial Park.

So the answer is, yes. Mark Whitley and his team will continue to drive up production and working with the pipeline companies, we are going to get all that on by the end of the year. There's two big programs, that's ETC Paris line supposed to come on sometime within the next 30 days, take away capacity of 300 million per day and the other one is a [Crowley] line which will be on line by the end of the year. That could add, depending on what pressure you are pumping, 700 Bs to or 700 million up to bcf per day and it will not come on all at once it will come on in parts, starting in September and October through November. So we'll be drilling in the Barnett where we are not curtailed, but when the curtailments come back on we are going to get that production. Like I said, it's a negative thing that we were curtailed but since it's happened now you can view it as a positive. We have got 22 million per day that is just opening valves to get it back online. No additional cost. No additional effort other than the third-party pipelines that will be put in place.

Great. Let me get back in the queue. Thanks.

Thank you. Our next question comes from the line of Rehan Rashid with Friedman, Billings, Ramsey & Company.

Good afternoon, Jeff. On the Marcellus from a water standpoint, I thought I read in Halliburton earnings transcript that they might be looking into something that would allow you to use Brean roe rather than portable water. Does that ring a bell? Any thoughts there?

Yes. That's a good point. There's a lot of technological things that are in the process that could really help out. We are planning for existing conditions as they exist and we'll have enough capacity for current technology. But what Rehan's referring to is the big issue with reusing frac water is friction reduces don't work in saline water. The service companies are working on the technology to come up with friction reducer that will work in saline water, that's true, then we can reuse a lot of the frac water. There's upside in terms of technology that will come down the line. Just like we are not counting reserves and rates from refracing horizontal wells. I believe in time the industry will figure out and we'll get the benefit of that. That is a nice technology that we are looking at in order to be more efficient with water use and there's literally three or four other things that we are doing as well as the industry.

Okay. On the Barnett take away capacity, 1 to 1.3 bcf per day roughly around the end of the year, how about beyond that? Is there more on the table to come from what I understood there might be a couple more bcf that are being proposed? Any thoughts on that front please?

There's other projects that are in the works and they are being talked about to continue to expand take away capacity out of the Barnett. The Barnett has been a great field. I think it's the biggest on shore gas field now in the US and very economic place to drill. Very robust economic and production growth so the pipeline companies are continuing to work with the producers and getting additional take away capacity out of the basin.

One last question. When you are trying to plan all across the board and everybody else is working on all different Shales plays as well, how are you thinking to your other infrastructure needs, tubular goods, frac capacity, how are you kind of -- generically speaking you are planning four but maybe some time lines in how far ahead you need to plan for fracking, anything else that comes to mind?

For instance our Appalachian team - - really all of our teams we take all of our properties and we forecast them out through the lives of the properties. So we have plans that look not just at development of our existing prove reserves but probable and possible in emerging plays beyond that and then we work with our pipeline guys and commercial guys, like up in the Appalachian Basin, not only plan for landing the infrastructure to it, to make sure we have firm take away capacity for the volumes of gas that we expect to produce.

Same on the drilling side. We know for 2008, end of the this year, obviously, all the way through 2009 and we are looking at 2010, in terms of number of rigs and types of rigs. Talked about it in our release two special built-for-purpose rigs we are ordering for Marcellus Shale play up there. The guys do a good job forward planning. I would argue, the prove is in the track record, we didn't get 22 consecutive quarters or five years of meeting or beating our marks without forward thinking in terms of what we are trying to do. We realize with some of the bigger projects, like the Marcellus Shale, and other areas that we need to do a lot of that kind of planning and we do do that.

One thing, Rehan, this is John. We've met with every single large take away capacity pipeline in the Appalachian Basin because they all want to understand what the Marcellus play is all about, the potential. Since we have more information, had a better perspective than anybody else and the most encouraging thing is essentially all these pipeline companies and utilities want to be in the Marcellus play in terms of providing take away capacity, and a number of companies, [Dominion] all the others several others have announced new projects and whatnot, and we are right in the middle of all that. So there's no better place on the planet earth to sell natural gas than the Marcellus Shale play. So in terms of the location, 60% of the United States lives within 3 or 400 miles of the center of the play. So it's a marvelous place to be selling gas over a long period of time. And there's no doubt in my mind that just what I've seen so far and the encouragement that I have seen from the other pipeline companies, it's just a matter of time, and I don't think it will take that long.

The infrastructure we are putting in place that should be up and running in the first quarter really will allow us to ramp up dramatically and just from some of the take away capacity, we are pretty confident in terms of the overall commercial of the play. Again I think you have to step back a little bit and just think about it, but we have 850,000 acres that we think we high graded. So it's huge for us and so therefore we are planning ahead more than I think we've ever had in terms of looking at some of that stuff. I'm very encourage in terms of where we'll be one two three years from now. I think it will be for those shareholders that were with us in the beginning, it's really going to pay off. It's a little patience here and it's going -- we are seeing today and all of a sudden the market will realize it will be reflected in our stock price.

Thank you.

Thank you. Our next question comes from the line of Ronald Mills with Johnson Rice.

Good afternoon. Jeff, can you expand a little bit on the Barnett Shale and when you walked through the 700 locations are you breaking the 500 foot spacing and 250 foot spacing among individual project areas or how should we look at that inventory?

Well, yes. Specifically we have all of our acreage and we have 3D seismic covering all of it and we have wells on all of it too. So it's low risk known part and our guys are going back through and literally posted up the wells that they think are good quality, high quality economic wells to drill in acreage we have. You have all the technical work the production data, the geology and the geophysics. On the stuff David Amend will put up on the website we will include some of those maps. So you will see some of our areas and it will show number of locations we have in the areas, it's will show quality of wells, recent results of our wells and some other people in and amongst those areas. In some cases it will talk about reserves and rates, well cost. So we will try to put that up on the website. David told me it will be up tomorrow. I'll give him an extra day. By Monday it will be up there. When we are out and about at Intercom and the other conference it will become part of our pitch book. We really just revised our pitch book to include all that, to make it more transparent.

Have you drilled any wells on the 10 acre or 250 spacing to get it at that data?

Again on the 250 foot spacing we assume 15% of our acreage would have that. So a small percentage and the acreage we are assuming are in the thick gut heart of the play in Tyrant county in areas like that. But we are amongst, where Devan has drilled like that, where EOG drilled like that, seven though this year we'll be drilling our first 250 wells, like in Carter Industrial Park. Other people in the industry have drilled in those areas and proven that it works.

Okay. And you mentioned the Chesapeake wells. Did that do anything in terms of validating some acreage that you thought may have been potentially more fringe as that moves further west from where some of your earlier activities were?

Absolutely. I mean if you look at our wells at this point, the distance between our two furthest horizontal wells is 40 miles, which is hugh in oil and gas terms, and we have quality wells in those areas. When you factor in the Chesapeake wells, which are in the west Virginia panhandle, farthest west of where we are, thinner and oiler, if you want to say it that way, less mature maybe it's a better way to say it, yes, having those wells out there is great news for us. And then also factoring in all the Atlas wells even though Atlas and I haven't seen the latest presentation but talking to Rich Weber and seeing their presentation. They had over 50 vertical wells that look really good. We are not just looking at our wells in the play. When you factor our 100 wells and Atlas that is 70 wells and Chesapeake new wells including the wells I hate to throw some of the companies but some of the wells that were drilled outside of those areas, I think we have a really strong geologic model that works and makes sense. That is why I'm excited.

At some point, hopefully next March plus or minus when the acreage is tied up we'll have an analyst day and we'll walk through our model and it's really interesting in terms of why did we target, how do we drill, why do we do that. But, yes. Jump back to your question though, those Chesapeake wells are good news. I'm glad for Chesapeake. Steve listens to our calls, so hello, Steve. And they are great guys. I'm happy for them but I'm glad for us because it's good news.

Okay.

And for those that they haven't heard they announced 2 wells at 9 million per wells.

And Roger, can you walk through the liquidity situation you talked about? I think you said you have 800 million available and then the next 1.3 billion of liquidity. Can you walk through that balance sheet again?

Sure. Thank you, Ron. Let me clarify that. We have an accordion facility with the bank group, and what enable us to do is we have a binding commitment of 1 billion under the commitment. They've underwritten our asset base and are willing to lend up to 1.5 billion in the borrowing base, if we need it, but we don't want to pay a fee for that extra 500 million and they don't want to have to book it as a commitment and accrue capital on it. So the way it works if we want to go from a billion to 1.5, we tend to notice with the agent and they survey the bank and they have 20 days to reallocate the exposure amongst themselves and come back. It's not a committed over line but it's a closer thing you can get to it. So my numbers there we have 800 million left on the committed liability of a billion, and if you add the 800 to the extra 500, you get the 1.3 billion I mentioned.

Great. And just on your cost guidance I missed what your expectations were from a G&A level and the numbers. Should we assume that excludes the non-cash compensation and also on the production cost, it sounds like you expected your LOEs to stay around a buck including work orders and the curtailment.

I think we'll do a little better. It's difficult to predict and $0.10 we have this quarter it's the highest quarter we've had. As for G&A, the cash number, cash G&A was $0.49. That will hold where it is until we get more production on. High $0.40 range is a good number.

Okay. And then production taxes is really no -- any shift of your production breakdown geographically? Should we anticipate any changes in that?

No. We continue to file and get the abatement in the Barnett for production tax. It is based on well price not hedge price. So that makes a difference. But just percent of production however you model it should continue to work fine.

Great. I'll jump back in queue.

Thank you our next question comes from the line of Marshall Carver with Capital One.

A couple of questions. First of all the number of wells per rig, per year in the Marcellus with the ramp up trying to get a feel for how many horizontals you'll be drilling in 2009.

Like I said we talked about going to eight rigs and wells. It's really early. Typically what we do just for the people that aren't familiar with this usually in August I ask the division on a wish list given the thing cost and rate of return criteria that they need to meet, what would they like to do for next year and then we enter a process. But to try to answer your question in a rough range I will put a pretty wide band. You are looking at 80 to 100 wells. Something like that. And again we are saying we will ramp up thousands the year. So you have to filler then in. But it's preliminary. It's early. He have to run it by the board in December and we'll put it out next year.

That's helpful. So in 2009 guidance would be coming out sometime this fall?

That's fair.

Okay. Thank you that's all for me.

Thank you.

Thank you. Our next question comes from the line of Jack Aydin with Keybanc Capital Markets.

Hey guys.

Hi Jack.

The taxes for the second quarter, the corporate taxes it was about 40%. First of all, why was higher than used to be and going forward what kind of tax are you thinking of?

Thank you Jack. Tax rate should be at the 38%. We had a blip in the first quarter from some deferred tax accounts that needed to be reallocated, but it will be 38% going forward.

Thanks. As it relates to the amortization of leases that would expire, could you -- Jeff, could you give us a hint where those leases are and what timetable, how long those leases are and what percentage of your acreage lends itself to those types of exploration?

Let me let -- Roger has that so let me turn that question over to Roger.

Good question. This is something that is a little new. Let me answer by putting it in perspective. Our total unproved property balances at the end of the quarter is 422 million. That's 8.68.6% of our total assets. When you look at it in perspective our unproved is way smaller than our peer group especially those with similar is shale emerging play upside. So we watch properties very very closely. We treat it as all our assets. We manage it very efficiently and it's our interpretation of the accounting rules and it's shared by our auditors that even though you account for our pool basis that anytime you have a lease that expires that you have a carrying value associated with it, you must take an impairment of that lease that expired. And what you are seeing in our numbers and I'm not sure why you are not seeing them in our peer group numbers, is that when you enter a play such as our the Barnett, when we purchased we book a fair amount of acreage value two years ago and as in any purchase it will not be good all the time. But when you make your purchase price allocation and this is going ton across the industry as you know. A lot of purchase prices being allocated to unproved acreage. When that acreage expires you have a big number that is rolled through the DD&A.

To answer your question some of the Strout acreage that is coming out on the two year mark that was already a year or so old when we bought the company, are in areas that we don't choose to pursue any longer and we are allowing it to expire. But it went books. It doesn't take much acreage to create the write-down. Conversely in areas where you have acreage down the street that is at 200 an acre or less, and that's a very small adjustment. So even though you look at a pool basis you can't look at the pool and say my acreage went up and so I will mark it off to offset the expiration. In answer to your question it's only acreage that was acquired in various transactions and right now most of it seems to be in the Barnett and looking forward the guidance I gave you 5 to $8 million per quarter should be sufficient to cover those expirations.

You are telling me with all the interest in Barnett and everything you cannot get somebody to drill wells on this acreage or you don't care to drill wells?

Jack when you look at our old maps it shows the Barnett acreage. The good news is it was in the core and we will put out very specific maps so you can see the areas we are talking about. When we say 95% was in the expanding core that means 5% is not. So the stuff that is down in county there was a tiny bit in Hamilton county -- our strategy is simple. We want to grow production double digit or better this year and we want all our cost structure to be better. We are not going to drill poor wells in some of the more areas or renew those leases. We would rather focus our areas in the highest rate of return best F&D than we would extend or drill some of the more marginal stuff. That is really what it is.

Thank you. John, did you give me a production number or guidance for the third quarter?

Yes. We think -- let me just go back over that, Jack. I gave for the third and fourth quarter. Third quarter 384 to 386 and fourth quarter 395 to $400 million.

Thank you.

You're welcome.

Thank you. Our next question comes from the line of Tom Gardner with Simmons & Company.

Good afternoon. I wanted to get clarity on your Marcellus reserve expectation specifically what percentage or what fraction of your high graded acreage would you apply is 3 to 4 bcf range.

All of it.

All of it. Do you see any reason to differentiate between your northeast area or your southwest area?

Yes. In terms of recovery per well?

Yes.

No, but there are other distinguishing things and we have a big development in the southwest for a number of reasons but we think we've drilled some very good wells in the northeast as well. And again we will in time become more and more transparent as the different models but because of the competitiveness in leasing we are going to withhold some of that. But in terms of the reserves, we'll go with the three to four bcf E. In terms of cost per well, in the southwest it's shallower and you are out of the spine of the mountain so wells will tend to be cheaper. Those will be toward the low end of the range. If you are up in the mountains and in areas to the northeast particularly some of those areas the Marcellus can be at 8,000 or 8500 feet deep. I would distinguish the cost but not distinguish the reserves.

Thank you.

Does that make sense?

It does. I appreciate that.

The other thing if I can just butt in and make a point, the one thing in the shale play that is really important in terms -- the cost side of the business is really important, and the interesting thing -- I'll give you an example in the Barnett and try to relay back to the Marcellus. Down in hood county we own 6 or 7,000 acres in the Barnett and we drilled good and Jeff mention that we have the cost down and those wells when we first started drilling we were using and the cost were 4 million per well. David in our drilling team really learned a lot. We drilled 15, 20 wells by now. We picked up for acreage. In the last few wells we drilled wells in three days. We drilled three days for the cost of what one well cost in the very beginning, and that same thing over time is going to happen in the Marcellus and the one thing that -- one real advantage that we've got because we own so much acreage in the beginning and we bought so much acreage before the play went really well we have huge blocks of acreage and I'm convinced over time the same thing will happen on our big block in the Marcellus as what we are doing in the Barnett. where we can drilling five or six wells and get the purpose rig. We have a really first class drilling team up in the Marcellus headed by John whose got 30 plus years of experience, maybe 40. So I'm convinced over time that $3 million that Jeff used on the -- we'll beat that over time.

To make it even more direct, John talked about the county wells there are 6500 feet deep and a lot of the stuff we are drilling. They are 3,000, 3500 foot lateral and there's a lot of similarities and granted you don't have the infrastructure but I agree with John's assessment that in time we'll beat those numbers.

And I'll argue that the infrastructure in the Appalachian the large pipeline, the big take away line is better. What you don't have the gathering system. The gathering systems are relatively cheap. The good news is that in the Marcellus once these gathering systems and we've got a number of them. Not just one but as we develop these systems there's a lot more take away capacity and the good thing about the Marcellus is -- it's on the front end of all the shale plays. So Marcellus gas will demand premium over gas or Barnett gas or any Woodford gas or any of these other gas, the Marcellus gas will get the highest price because it's the closest to the end-user and it's got -- within -- I did a rough analysis six of the eight pipeline systems in the US run through our Marcellus block.

It's just a matter of gathering the system built. We've been operating up there for years. We've got this deal with MarkWest. We are talking about deals with other midstream. It's just a matter of time. I'm convinced it will work and we'll -- the good news is we'll talk about 30 million blank and blank and everybody will forget all the silliness over the infrastructure. I would just continue to focus until you guys that the infrastructure is just a matter of time. It's coming. There's a lot of people chasing the infrastructure up there with a lot of money. It's it will get there.

And I agree with that. When I say it doesn't have the same infrastructure, if you back in the early years talking to Mark and the guys, when a lot of other operators weren't ramped up and had more drilling companies a lot more pumping companies and all those types of thing but all those companies we talked to. They want to be there. I agree with John. That will happen.

Then the question is how fast can you go? You are planning eight rigs for 2009. Can you walk us through the possible upside there, the activity in 2009 and beyond?

Yes. I think I would just draw you can draw the analogy and the easy analogy is back to the some of the other plays. We'll be able to ramp up significantly. We talk about 2009 being at rigs plus or minus. And then we have a significant ramp up in 10 and 11 and beyond. We'll see if we can get 20, 30 rigs with continued delineation. The answer is yes. So but obviously it's early to say that and we need to continue drill wells. We are looking to optimizing. We are in the process of shifting.

If you go back to 2004 it was an idea. Could the Marcellus Shale be a significant shale play and we were the industry leader in that. We came up with the idea. We tried it. Now we are moving from, yes, it does work. We drilled a number of excellent wells. Talking about the last seven wells at 4.9 million per day. Those would be excellent wells. That would be good wells in Johnson county. That would be phenomenal wells. So now we've gone from the idea worked to can we turn it into a development project, which is what we are currently doing and then it comes back to ramping up and optimizing NPB. We are all heavily invested in the company, and clearly we want to maximize that value for our shareholders and ourselves.

That's fair. One last question. Just an idea of what your reserve expectations and well costs are going forward and what is the greatest risk for this if this becomes a successful resource play.

The easiest thing to look up there is all the work that they did in Kentucky plus we now have three wells on our own property. It looks like based on the equitable stuff, they are talking about reserve .8 to 1.6 million per well or something like that. Based on our earlier work those numbers seem to hold up. I'm confident that the shale -- you have 100 control point and I know now that horizontal drilling works in three spots. So we'll be basically equally distributing those wells across the acreage. By the end of the year, we'll be risk about a tcf and a half and that's basically using roughly 100 acre which is in line with what equitable.

The other thing I talked about is and I just mentioned it but the potential for a horizontal bring a there. It is the original more information that was developed from the 1950s and the wells are good but again equitable in the area or in the vicinity is horizontal wells and last I've heard and they obviously would have more up to date information. They have two wells and each averaged over 2 million per day per well for the first 30 days. We have a big Brie, a fairway on our Nora block that is an excellent candidate and there's a chance we might take a couple of those ten wells and drill perhaps eight wells and convert a couple of those to horizontal Brie. That could in addition add up net to range as well as equitable. Thank you so much guys I appreciate the information.

Thank you.

Thank you. Our next question comes from the line of Brad Olsen with Tudor, Pickering, Holt & Company Securities. Proceed with your question.

You have, David. Thanks for the long call trying to get to the question. John and Jeff, you talked about efficiency and the Barnett and people's on rate count. I wonder about thinking about efficiency and drill with your current rigs the purpose rigs any of the characteristics of that and thinking about more of the well count than on an efficiency basis as you improve, what has your ideal well been if you did everything right on the 25 horizontal wells that you drilled? Can you give us any of that information?

Yes, today if we did everything right, it won like 3.3 million per well for wells in Southeast Pennsylvania horizontal. So that is assuming no additional productivity gains, no bill for purpose rigs, no pad drilling, no optimization of bids or anything like that. That is why I've said for a while we'll get in that 3 million per well complete range and like John said I believe we have team there. In time they'll beat it whether it's on well 50 or 100. But if we have several thousand wells to drill those guys will do a good job. That is just eliminating the trouble and taking the signs out of our existing well that gets us to that 3.3 million today.

That's helpful. Just on the Brie. You talk about a fairway. You also talked about testing the going up in Pennsylvania and the other. How much capital do you invest in testing the new ventures in the back half of the year?

In the Brie a, the Brie a is pretty interesting and easy because we have several hundred vertical wells. So we know in the Nora block we know where it is and what the thicknesses are and it's a great vertical target. I believe it will be a better horizontal target. So we'll probably take two of the ten wells that we have scheduled and convert them to Brie a wells. So there won't be any In capital. We've been studying the you'd . We got in the Marcellus in 2004, and several good other things have popped out. One we recognize the potential. So we've been talking about it's and I was just up in our offices and saw a pretty complete study. So I would imagine sometime next year we'll drill our first you'd well. We have a big footprint occupy there. We already have the acreage.

So there's no incremental acreage cost. It's just going out and trying it. When we haven't put our budget together. We do that in the fall. But we'll probably have one or two wells for next year. The other thing the other shale to protect are all Devonian shales. So as we drill our roughly hundred vertical and Marcellus Shale drill we'll drill right through those. When we run our logs we have ECS logs across those. We have across some of those intervals. And we think there's some good opportunity out there. We haven't put out or quantified it yet or released any of that information, but next year you can be assure we'll be testing some of that as well. And probably between now and the end of the year we'll quantify the upside of all those various horizons and at the appropriate -- whether we do it this year or next year, when we update our emerging place we'll have those other horizons in

Acreage in Ardmore basin now, did you add acreage there or what is your total?

We have 16,000 net acres. It's over 100 acres gross. So we have a big footprint, but in some areas we operate and control. The other areas that we don't, they are operated by Chesapeake and those companies are drilling and we are drilling where we operate. It's early on. There is some encouraging things coming out. And the thing to remember is the Ardmore basin, Woodford versus [Arcoma] that the wells are significantly cheaper. It's easier drilling for a number of reasons so the well costs are about half. And we've gotten some interesting results so far. Probably need another quarter or two of testing before we put a lot of information out. But we'll know a lot more by the end of the year. And that could be 400 Bs net to Range. So so far so good.

Thanks Jeff.

Thank you. Our next question comes from the line of Leo Mariani with RBC. Please proceed with your question. Your line is currently live.

Good afternoon. To follow up on the Marcellus here, you guys have 22 wells that you tested horizontally. Any on production at this point in time, or are they all waiting for the higher pressure gather to come in the first quarter of '09?

Some of those are on production and some have been production for basically approximately a year. So we have a year's worth of history. The other thing when you talk about shale play in general, we have 100 total wells, 22 horizontals. Our oldest horizontal for about a year. So we are gathering reasonable production data. You are right. We have a number of wells we drilled that we've drilled and tested and in some cases we'll test them up to 30 days. So we have good long testing and when we did our facility and equipment in place, those will come on line and that's the first quarter next year. So not only do we have 22.5 million of Barnett production that will come on line over the next by the end of the year. We have a significant amount of Marcellus production that will come on line and that is why we are coming at we'll be 30 million a day by the next quarter.

So those couple horizontal wells those are being curtailed at this point or some areas where we have the gathering that could handle that kind of volume?

We have some gathering and it's not just a couple. There are several of them. So we have good long term test on a number of wells that are uncurtail so we have a good feel for how they produce.

In terms of just take agriculture look at 2009, you talk about getting into 30 million a day in the first quarter. Is it reasonable to assume you guys talked about having 130 million a day of firm take away that you will be able to step that up? Are you guys working on gathering projects to get out there and hook up more wells each quarter successfully there?

Let me clarify. I said 130 by mistake. It's 150. That is what we currently have secured but we are well in the process of doing more than that. We'll continue to look at ramping up and optimizing and that type of stuff.

Okay. Thanks a lot.

Thank you. We are nearing the end of today's conference. We will go to Dan McSpirit with BMO Capital Markets for our final question.

Thank you and good afternoon. A lot more gas will be coming out in years 2009 and beyond. Could you comment on what you think happens to the premium place on gas today and I guess I ask that in the face of maybe sluggish to down or flat demand growth in the northeast markets.

Well, a couple of things. I think production will it will be primarily -- will be up, but I don't think it's going to be -- flat the market. It will ramp up over time and we are the leader in the play so I think everybody else will be a bit behind us in a material way. But I think gas will come on over time. I think there's a number when you look at the landscape in terms of the northwest, there is a number. It's not an easy occasion but there's a lot of things that give me very much in terms of natural gas. One is roughly 50% of what crude oil is trading for. So I think there will be upward pressure on natural gas in terms of just being a commodity versus oil. There's a lot of generation that has got to be built in the northeast very quickly over the next five to years. Natural gas won't be -- I think a lot of the coal is being challenged due to the carbon footprint even clean which I think is a misnomer can't compete with natural gas. Coal prices are up substantially. So I think natural gas will be clearly the victory in northeast. It will be in other parts of the US too. I am not too concerned and the good news is that we think our Marcellus play is going to be $1.50 or better, in terms finding cost. I don't worry about gas whether it's 7, $8, $10, or $12.

I think when you step back, when you look at natural gas, it is the only thing that I see and I'm trying to be objective here but obviously it's because we are natural gas, but when I look at the other sources that will drive all this, to me in the short-term, and I mean short-term zero to ten years, natural gas is the only one that can cover that unless we want to continue importing foreign oil which I think if we don't do anything it will be $200 a barrel or to include with some -- at the end of the day it's all going to come back to natural gas, and the good news is a lot of these big electric generation facilities are going to need firm long term commitments. And we've already been talking to a number of them wanting to firm that up. So I'm seeing it realtime in terms of some of the inquiries from some of the big power generators up in the northeast. I think will if there is a hurricane doesn't come or the weather is a little different, sure. Those are short-term events but when I look at the next one, two, five years for natural gas I am very bullish and make it more bullish in terms of that.

I'd like to add one thing. John mentioned the economics and referred to the economics in the Marcellus. This stuff I talked about earlier, David will have a graph on the website either tomorrow or Monday, and of course we'll use different analyst stuff. [Shana Nome] with Deutsche Bank just completed a study of all the shale plays across the US, including the Marcellus and the Hainville, Woodford and Barnett, and that will be up on our website. It's a good piece of work, and I'll encourage you to look at that as well.

Thank you.

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

I want to thank everybody for staying on. I know we've run over but I think there were a number of questions we needed to answer that you all wanted to answer. So hopefully we were able to answer a lot of those questions. I think as I talk to our shareholders, the things they tend to want to know are the things that -- the hard thing is to get your arms around, which is some of the water issues in the Marcellus (inaudible - background noise) and I just want to make sure that we are on top of that. We know what we are doing. We have the right people doing the right things. We wouldn't commit to eight rigs. We wouldn't be committing 150 million a day of capacity. If we weren't confident that these things would resolve selves over time. We know a lot that we are not disclosing for competitive reasons but we are very confident in terms of the information we are giving you, in terms of the Marcellus, the project progress we are making in terms of infrastructure.

So I think those of you who have been in the Range stock for a time in '04 and '05, if there's anything I can give you advice on is to we are just around the corner here. Everybody will be pleasantly surprised with some of the stuff when we come up with more of the technical data. You rode this pony for a while, I'd suggest you stay on our backs and we'll get you to the finish line. I promise you that. With that, again we appreciate you staying on. If there are any questions, feel free to call. Roger, I, Jeff, David, or the others at Range will be happy to answer. Thank you very much.

Thank you for your participation. You may disconnect your lines at this time.