山脈資源 (RRC) 2009 Q2 法說會逐字稿

Welcome to the Range Resources second quarter earnings conference call. This call is being recorded. (Operator Instructions). After statements contain in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks there will be a question and answer period.

At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon and welcome. Range Resources reported results for the second quarter of 2009 with record production leading the consensus number and clearly continuing to execute our business plan for 2009. In trying to be as transparent as possible but still maintaining our competitive advantages, Range Resources shared a type curve of our first 24 horizontal wells in the Marcellus that have had at least 120 days of production history. We've also compared our Marcellus results with various other share place holding that data from existing public data.

Both Jeff and John will give more color on our Marcellus results today on the call. On the call with me are John Pinkerton, our Chairman and Chief Executive Officer, Jeff Ventura, our President and COO, and Roger Manny, our Executive Vice President and Chief Financial Officer.

Before turning the call over to John I'd like to cover a few administrative item. First, we did file our 10(Q) with the SEC this morning. It's now available on the home page of our website our you can access it use the SEC Edgar system. Also available on the home page is the slide showing our Marcellus type curve and comparisons to other shale plays. In addition we posted on our website supplemental tables, which will guide you in the calculation of the nonGAAP measures of cash flow, EBITDA, cash margins and the reconciliation of our nonGAAP 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, we will be participating in several conferences and roadshows in the upcoming weeks. Check our website for a complete listing of those in the next several months. We will be at Intercom's oil and gas conference in Denver on August 10th and 11st, the Tudor Pickering forum in Houston on August 18th and 19th and Barclays' CEO energy conference on the September 9th and 10th in New York.

Let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the first quarter financial results I'll review the key accomplishments for the second quarter. On the year over year basis second quarter production rose 14% beating the high of the guidance by almost $10 million per day. This also marks our 26th consecutive quarter of sequential production growth. The driver for the higher than anticipated production was some exceptional drilling results both in the Barnett and the Marcellus shale plays. Our drilling program was on schedule throughout the quarter as we drilled 145 wells. We continue to be extremely pleased with the drilling results and despite the low prices continue to generate attractive rates of return. Currently we've got about 14 rigs running, which is down about half of where we were last year when we had about 30 running. The 14% increase in production was more than offset by a big 32% decrease in realized prices. As a result second quarter financial results were lower than the previous year.

We are most pleased on the cost side as our controls of cost were well in line with expectations. Unit operating costs came in at $0.86 per Mcfe, that's 18% lower than second quarter last year. Right at the quarter end, we closed the sale of our Fuhrman-Mascho property in West Texas for $182 million. We received an excellent price for the property and will recycle the proceeds into a higher return projects. As I said before, we view asset sales as a way to fund our capital program, high-grade our asset base, maintain a low cost structure and focus our technical teams on our higher return projects. I want to congratulate Chad Stevens and his team for excellent work they did on the Fuhrman sale.

With regard to our Marcellus shale play significant head way was made in the quarter as we continue to drill some terrific wells, high-grade our acreage position, build out infrastructure and bring down our well cost. In addition, we continue to add some high quality technical personnel to our growing Marcellus team in Pittsburgh, Pennsylvania. All in all I couldn't be more pleased with how much we've accomplished so far in the year. It's a real testimony to the entire Range team.

With that, I will turn the call over to Roger who will do our financial results.

Thank you, John. The second quarter of 2009 bears many similarities to the first quarter of this year as oil and gas production set a new record high, up14% from second quarter of last year. Direct operating costs were down significantly and our liquidity and balance sheet were stronger at the end of the quarter than at the beginning. Unfortunately, all of these favorable items occurred against the backdrop of continued lower oil and gas prices. Oil and gas prices on an Mcfe basis were 32% or $2.85 lower than the second quarter of last year. Quarterly oil and gas sales including cash settled derivatives totaled $244 million, that's down 22% from the $313 million in revenues last year. As John mentioned, the 32% drop in prices more than offset the 14% increase in production.

As we will discuss further in a moment operating costs were significantly lower this quarter. In fact, the lowest since 2007. Cash flow for the second quarter of '09 was $156 million, 29% below the second quarter of 2008. Cash flow per share for the quarter totaled $0.98, that's $0.02 per share higher than the analyst consensus estimate of $0.96. Quarterly EBITDAX of $185 million was 24% lower than the $244 million earned in the second quarter of '08. Second quarter cash margins were $3.93 per Mcfe compared to $6.37 per Mcfe in 2008. Cash expenses per Mcfe were down an impressive $0.39 or 14% from last year, these savings were overshadowed by the decline in oil and gas prices. Mark-to-market hedge accounting drove a $62 million non-cash mark-to-market loss in the second quarter compared to a loss of $162 million last year. Another non-cash revenue item worth mentioning is the $4.6 million loss on our equity net investments, primarily our 50% investment in an Appalachian drilling company.

Skipping to the bottom line for a minute before discussing our cost performance, quarterly earnings and calculated using analyst consensus methodology for the second quarter of this year were $34 million or $0.21 per fully diluted share. That's $0.03 higher than the analyst consensus estimate of $0.18. In the GAAP net loss for the quarter was $40 million, compared to a net loss of $32 million last year. As Rodney mentioned the Range resources Web site contains a full reconciliation of these nonGAAP measures including cash flow EBITDAX and cash margins.

The expense categories for the second quarter of '09 reveal the impact of lower oil and gas prices and resulting reduced demands for services. Cash direct operating unit cost was $0.86 per Mcfe in the second quarter of '09 less $0.07 lower than the first quarter of this year and an impressive $0.19 per Mcfe lower than the $1.05 figure unit cost in the second quarter of last year. Work over expenses were $0.02 per Mcfe, that's $0.08 lower than last year. That accounted for some of the decrease. As I mentioned earlier, the last time cash direct operating costs were this low was back in 2007. Production and lower taxes per Mcfe were 53% lower than last year's second quarter then reflects lower oil and gas prices. Production taxes totaled $0.19 per Mcfe for the second quarter of '09, that's compared to $0.46 last year. Now we expect cash direct operating costs to be in the mid to high $0.80 range for the rest of the year.

General and administrative expense adjusted for non-cash stock compensation was $0.51 per Mcfe, that's up a penny from last quarter and up $0.02 from the second quarter of last year. The G&A expenses still increasing is in the continued build out of our Marcellus shale division. With the Marcellus production now growing concurrently with the G&A expense we are beginning to see the rate of G&A unit cost expense growth begin to moderate and cash G&A expense anticipated to be in the $0.53 to $0.56 per Mcfe range for the rest of '09 because we staff up for 2010 Marcellus development. Interest expense for the second quarter of '09 was $0.75 per Mcfe, that's up $0.04 from the first quarter and up $0.06 from the $0.69 figure last year. The upward pressure on interest expense stems from our decision to refinance $300 million in short term floating rate bank debt with longer term figured rate subordinated notes during this quarter.

Exploration expense for the second quarter of '09, excluding non-cash stock compensation, was $10.5 million. And this expense was $8 million below last year but the reductions being evenly split between lower dry hole cost and lower seismic expense and somewhat unusual in this business even for range to have no dry holes in an entire quarter as we did this quarter but we expect exploration expense to return probably to the $12 million to $14 million range per quarter for the rest of the year. Completion, depreciation and amortization per Mcfe for the second quarter was $2.25, even with the first quarter of, and $0.17 higher than the $2.08 figure from second quarter last year. $2.10 of the $2.25 figure is from depletion. $0.15 is from depreciation and amortization of other assets. Our DDA rate should remain at or just being slightly above the $2.25 figure for the rest of the quarter.

On the first quarter conference call, I explained the nature of the unproved property account and how the impairment and abandon process works. I stated that the expense figure will continue to vary quarter to quarter and our best estimate of future quarterly non-cash abandonment expense is in the $16 million to $19 million range. That's since the second quarter of 2009 impairment and abandonment figure was $41 million, the first half of my prediction about the number of varying was clearly correct but the second half was off. Now, $22 million of the $41 million provision for impairment relates to Barnett leases, where we elected not to renew the leases due to marginal economics at today's prices. The remaining $19 million amount represents a combination of our regular amortization and a provision for specifically identified leases that we believe should be impaired based on current economic conditions.

Now because so many of you have asked questions about this untrue property process and unproved property impairments, I would like to again revisit the issue this quarter, but instead of explaining the detail of the unproved property process, I will focus at the macro level this time. Range is one of the only major shale resource players to use the successful methods of accounting for oil and gas properties. Devon, New Field, Planes, PetroHawk, Sand Rich, Chesapeake, Quick Silver, South Western, Hexco and Forest are all full cost accounting method company's. This is significant in that there are major differences in how these two accounting methods treat the disposition of undeveloped lease hold or what accountants call unproved properties. One difference is that delay rentals and other cost to hold unproved properties are expensed under successful efforts, but capitalized under full cost. The most significant difference, however, is what happens to unproved properties when they are impaired or abandoned. Under successful efforts once an unproved property is deemed to be impaired for any reason whether it's a dry hold build on the property or the property next door or a cut in your exploration budget or just marginal projected economics due to declining oil and gas prices these things happen you must immediately take impairment against earnings. Full cost producers on the other hand do not expense the impairment, even if the properties impaired to the point of being worthless. An impaired unproved property under full cost rules is transferred from the unproved property account to the full cost pool, where it becomes part of the amortization base and is depleted through DD&A based on units of production. In effect, this spreads the cost of worthless acreage over the producing life of the full cost pool of assets resulting in a higher ongoing DD&A rate but no one time charge. This is very similar to the way full cost cutting method handles dry holes. They are not expensed as they occur, but amortized overtime as part of the full cost pool. The day of reckoning for full cost of course is the quarterly ceiling test, which uses strict point in time oil and gas prices to test these capitalized costs in the full cost pool against the calculated net present value.

Now the ten full cost shale company's I previously mentioned posted an aggregate pretax ceiling test impairment at year end '08 of $27 billion an additional $25 billion in the first quarter. Embedded in this $52 billion of write-offs our previously capitalized dry holes and impairment acreage. These non-cash charges are largely ignored by investors as an inevitable byproduct of the full cost of accounting rules, yet because use successful efforts of accounting similar yet much, much smaller non-cash impairments seem unusual and out of place. South Western Energy for example, a full cost company we admire greatly that has shown everybody how to properly execute a shale play, had a $907 million pretax property impairment in the first quarter this year. Not being familiar with the nuances of the accounting rules, one could easily come to the false conclusion that a successful efforts company like Range with continuing unproved property impairment must have inferior acreage to a full cost company without such impairments or that acreage impairment by successful efforts company should be treated differently than a ceiling test right now by a full cost company. Now this is clearly not the case. There are two companies besides Range Resources that are significant shale players and use the successful efforts accounting method. They are EOG and Cabot.

There are $41 million provision for unproved properties this quarter is consistent with historical impairment figures reported by these other companies. We continue to believe that the quarterly provision for unproved property impairment will run in the $16 million to 19 million range though this amount will vary based on a myriad of factors many of which remain outside our control. Many recorded a benefit of $23 million in deferred taxes for the second quarter and we recorded $619,000 in state level cash income tax. While producing no book gain or loss, the successful sale of the Fuhrman properties resulted in an approximate gain for tax purposes of $140 million. Now Range will shield this gain using deductions from this years drilling program such that our $160 million NOL carry forward will not be reduced. Range's essentially fully hedged for the remainder of '09 due to approximately 80% of our gas production hedged as a floor price of 749 per MBTU. Earlier in the second quarter of this year, we began to layer in hedges on our 2010 gas production. We now have colors in place covering approximately 47% of the first half of 2010 production. The floor price of 550 in MBTU and a ceiling of 744. We have approximately 24% of our second half 2010 production, hedged via colors at 550 by 750 per MBTU.

Now there's several good news items from the balance sheet this quarter. We ended the quarter with lower debt to cap ratio than we started and successfully issued $300 million of ten-year, 8% senior sub notes at a yield of eight and three quarters. As a measure of Range's standing the in the credit markets these notes have been the only ten-year no call five notes issued by a high yield E&P company this year and we are the first ten-year no call five subordinated notes issued by any high yield issuer in any industry this year. The eight and three quarter percent yield is the lowest of any YTD double B E&P issuer regardless of maturity or structure. The combination of the $300 million note issuance and receipt of the proceeds of the Fuhrman asset sale reduced our bank debt balance to $403 million, down from $807 million at the end of the first quarter. The $403 million bank debt balance provides Range with over $1 billion in unused borrowing base capacity and approximately $850 million in committed liquidity.

Now looking back on the second quarter of '09, Range delivered better than expected operating results than noted double-digit quarter of production growth and significantly lower operating cost. The successful asset sale completed during the quarter combined with the $300 million note issuance strengthened the balance sheet and more than doubled our liquidity cousin. Both good things to accomplish in this business environment.

So, John, I will turn the call back over to you.

Thanks, Roger. Let's now turn the call over to Jeff to review our operations.

Thanks, John. I'll begin by reviewing production. For the second quarter, production averaged 434 million cubic feet per day, a 14% increase over the second quarter of 2008. This represents the highest quarterly production rate in the Company's history and the 26th consecutive quarter of sequential production growth. Looking forward continuing this streak will be a challenge. We closed on the sale of our Fuhrman properties right at the end of the second quarter, so our net volumes starting in the third quarter will be reduced by about 15 million per day.

I'll begin the operations update with the Marcellus shale and the Appalachian basin. To date, Range has drilled and completed 46 horizontal Marcellus shale wells. 41 those wells are currently online and today we are producing over 50 million cubic feet equivalent per day net. 24 of those wells have been produced for more than 120 days and some for almost two years. Utilizing these 24 wells for the first time, we released what our type curve for the average expected ultimate recovery of these wells. The expected gross ultimate recovery for this average well or type well is 4.4 Bcfe. Our current cost to drill and complete one of these wells in southwest Pennsylvania from a multi-well pad is $3.5 million. For a wet gas cast after processing, the BTU content of the bass is 1150. We currently get paid for the BTUs therefore our price is NYMEX times 1.15 plus $0.28 since this gas still receives a premium to NYMEX because of its location in the Appalachian basin. Our average royalty here is 15%. Drilling economics for Range's average southwest Pennsylvania Marcellus shale to date we spent $3.5 million to get 4.4 Bcfe. Factoring in the production profile, which is shown on our website, our average royalty and current gas price adjusts and assuming a $5 per MMBTU gas price results in a 50% rate of return and a cost to fine and development of $0.95 per Mcfe. At $7 gas, the rate of return increases to 79%. We believe this is the best rate of return and finding costs of any large scale repeatable play in the United States.

In the past stated that the average reserve expectation across our acreage position is in the three to four Bcfe range. To date, our average well has been about 4.4 Bcfe, which is above the top ends of that range. I urge caution that more wells and more production are necessary to determine what the actual number will be. We are still very early in the development of this play. For now I'm still comfortable with the three to four Bcfe range for the expanse of our acreage.

In the south western part of the play, we have approximately 550,000 net acres. To date we have drilled and completed 108 wells in this area. 46 of these wells are horizontal wells and all were successful excluding the initial science wells. The distance between our northern and southern most horizontal Marcellus shale wells in southwest Pennsylvania is 40 miles. The distance between our eastern and western most horizontal Marcellus shale well in south western Pennsylvania is 41 miles. Within this box, we have 173,000 net acres or 32% of our 550,000 net acres in this part of the play. Of course, we feel very strong about this area. We consider it low risk and have moved it into the commercial development of this area.

In the same area the distance between the industries northern and southern most wells is 81 miles. The industries eastern most and western most wells in southwest Pennsylvania is 59 miles. Within this box Range has 380,000 net acres or 69% of our 550,000 net acres in southwest Pennsylvania. Approximately 250 industry wells including Range's wells have been drilled in and around Range's acreage, which has significantly derisked even more of Range's acreage. Using just the 380,000 net acres within this low risk high chance of success area, in essence a derisk box and assuming 80% of the acreage is ultimately drilled and assuming 80-acre spacing, we can potentially drill 3,800 horizontal wells. Assuming 3.5 Bcfe per well, that's 13.3 Tcfe gross or 11.3 Tcf net unrisk reserve potential for Range. Range Resources is currently at 2.7 Tcf company therefore we have the potential to grow significantly from just this play in just this area. Importantly the rate of return on this capital expenditure is exceptional.

In the Northeast part of the play we have an additional 350,000 net acres. This represents another five to seven Tcfe of net unrisk reserve potential for Range. By the end of August we will be spudding the first of two back to back horizontal wells in the Northeast. Both horizontal wells offset excellent vertical wells that were previously drilled and tested. We also see significant upside in both the Utica shale and upper [Divonian] shale on portion of our acreage. We currently plan to spud to horizontal wells to test each of these concepts by year end. At year end 2007 Range's Marcellus production was about $8 million per day net. At year end 2008 we were producing about $26 million per day. At year end 2009 we will be producing between $90 million and $100 million per day and we currently plan on doubling that to $180 million to $200 million per day by the end of 2010. Future growth beyond that looks very encouraging. By late this year, early next year, we expect to have $200 million per day of take away and processing capacity. We just recently announced ing an additional $120 million per day of processing capacity which will bring our total capacity when installed up to $320 million per day. We have a first class midstream and marketing group and I'm confident that they will keep ahead of our drilling team.

I want to take sometime to discuss our capital efficiency, where we've been in the past and where I believe we will be in the future. According to a Bank of America study considering all in cost structure, Range has been the lowest cost producer in our peer group or second lowest cost producer for last five years in a row. When Range was first South Western was second, when Range was second, South Western was first. The five-year time frame that I'm referring to is 2004, 2005, 2006, 2007 and 2008. Today, Range's top three projects are the Marcellus shale, Nora and Barnett shale. Over the last five years these projects a played a very different role than the role they will playing going forward. Over the last five years, the Marcellus shale either insignificantly or negatively impacted these numbers. The reason is that our first test of the Marcellus was in 2004. Our early efforts involved pioneering the play, exploratory and delineation drilling, experimentation, data gathering and acquiring lands. One we found commercial gas, we began to go up the learning curve in finding ways to improve production and reserves and just recently this year in particular began to drive down costs.

2009 is a water shed year for us and first major processing plan was installed in late 2008, allowing to us begin development pad drilling this year. Pad drilling couple with new specialty designed rigs has allowed to us achieve development rigs that currently cost 3.5 million to drill and complete. Over the last five years the Marcellus exploratory/ delineation/ land grab/ science project has been a drag on our operating results. Given the success that Range has had in discovering this field and pioneering this project, the Marcellus now has become the premiere shale play with what we believe are the best economics and upside of any shale play in the United States or for that matter in the world. Going forward, low F and D, low LOE and premium mix should help to keep Range as either the best or one of the best low cost high organic growth companies in the business.

The same is true of our other two place, the Barnett shale and Nora. Range didn't start drilling in the Barnett until mid year 2006. Our first full year of drilling was in 2007. In the five-year Bank of America study referenced previously, the first three years, 2004, 2005, 2006 included zero or minimal impact from the Barnett. The last two years, 2007 and 2008, did include Barnett drilling but included in that effort, included in that was our effort to push the play south into southern Johnson County and further south into Hill County and an effort to also push it east into Ellis County. Although we were successful at finding gas in the Barnett, these areas are outside of what is now the well defined core of the Barnett. These are areas have a significantly higher F and D cost and lower and significantly lower rate of return than the core of the Barnett. Beginning in 2009 all of Range's drilling will only be in the core. This area has had a much lower cost structure and therefore we expect the next five years will have a much better cost structure going forward than the previous five years. We have over 1,000 locations left to drill in the quarter.

Nora should also have a much more significant impact on keeping Range's cost structure down in the future than in the past. There are three reasons for this. The first is that Range did not begin drilling in Nora until 2005. Therefore, Nora had zero impact on the first year of the referenced Bank of America study. The second reason is that until Range equalized its interest in Nora with EQT in the Spring of 2007, we had a significantly lower interest in Nora. So although Nora results were included in 2005, 2006 and 2007, it was in a much lower interest. The first full year of impact of Nora was in 2008. The third reason that Nora will be more impactful going forward is due to horizontal drilling technology. We expect that drilling the type gas sands and shales horizontally will result in improved economics.

Keeping with the theme of improved capital efficiency from Range, not only will each of our top three projects gets significantly better with time, they are now becoming the dominant portion of our capital spending. For the five-year period from 2004 to 2008, we spent significant capital in Fuhrman Mascho, [Conger], Clinton and Medina type gas sands, Watonga-Chickasha in the Gulf Coast, Austin Chalk, et cetera. This year in 2009, 90% of our capital is going into the Marcellus shale, Nora or the Barnett shale. These three plays have a significant higher rates of reason, significantly lower F and D and LOE and however, have better rate growing than any of our other projects lifted and also have significantly higher reserve upside. So as good as Range has been in the past, we should be even better in the future. The F and D costs for all these three properties range from about $1.00 to $1.50 in the LOE from all three properties are low. It's also important that two of our top three projects are in the Appalachian basin, where the gas price is better than anywhere else in the US.

Range consistently delivered to that tier organic production and reserve growth with one of the lowest cost structures in the business. This is a direct result of our simple strategy of strong organic growth to top quartile cost structure or better and in addition, consistently building and high-grading our inventory, coupled with one of the best teams in the industry. Range today has more upside and lower risk upside than in any time in the Company's history. With our inventory 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 combined with an excellent cost structure will result in continuing to create strong shareholder returns overtime.

Back to you, John.

Thanks, Jeff. Thank you a terrific update. Now let's look ahead a bit. Looking to the second half of 2009, we are, we see continued strong operating results. For the third quarter we are looking for production to average $430 million to $435 million per day, representing 11% increase year over year. The third quarter will reflect the full impact of the sale of our Fuhrman Mascho field which we closed on the last day of the second quarter. Fuhrman produced approximately $15 million per day net. So due to the timing of the Fuhrman sale, third quarter production will most likely come in slightly less than the second quarter. If so we will break our quarterly production increase streak. However, selling Fuhrman was clearly the right thing to do especially given fact that we got a very good price for it.

All that being said, with the momentum from the excellent drilling results that we've had so far this year, we currently believe we will achieve double-digit production growth, again this year, even after taking into account the asset sale in the much lower capital budget. Given our reduced capital program we are focusing over 90% of our Capex, as Jeff mentioned, in the Marcellus Nora and Barnett plays. These three plays generated attractive rates of return even at low gas prices. We are fortunate that the remaining properties in our portfolio have shallow declining curve. In particular our type gas and CBM properties in Appalachian are in decline of less than 10%.

One of the key elements that have a very positive impact on our results this year relates to the capital efficiency. In the past we spent considerable capital in the Marcellus without seeing much of a return. In October of last year this off changed as the first fades of the infrastructure was completed and production began to ramp up. As the Marcellus production continues to ramp up in 2009, we will see the capital efficiency impact have an ever increasing impact on Range. This is allowing us to do more with less. In the second quarter our Capex totaled $165 million including $16 million of Marcellus acreage we acquired in exchange for Range common stock. So, our cash Capex was $149 million in the second quarter, which was fully funded by $156 million of operating cash flow. For the full year 2009 our cash flow and completed asset sales will be more than adequate to funds our capital program.

Lastly I want to spend a few minutes discussing the Marcellus shale play. In our operations news release that we put out a few weeks ago and as Jeff talked about, we announced the our estimate of the average gross ultimate reserves of our 24 horizontal Marcellus wells that have been on production for 120 days or longer. On average these wells have been on production for 313 days, almost one year. Our estimate indicate gross ultimate reserves for these 24 wells will average 4.4 Bcfe. Given our early in the play we are still believe that three to four BCF per well is a reasonable estimate when one thinks about Range's entire acreage position. More than ever we strongly believe that where your acreage is located is extremely important.

We have also provided an update well cost number of $3.5 million per pad drilling from southwest Pennsylvania. We also posted on our website a slide that shows not only the declining curve projection for the 24 wells but also our rate of return estimate. The reason we did this is to provide a picture of what really matters, which is the rate of return we are generating in the Marcellus. Using a $6 NYMEX gas price held flat forever adjusting for basic differential our Marcellus drilling projects a 64% rate of return and Jeff also gave the number at $5, and $7 flat. This concurs to compares to 52% for the Fayetteville core, 39% for the Barnett core, and 36% for the Haynesville core. While the numbers will certainly change as each of the shale plays drill out, this is our best estimate given the public data current available and looking at other companies presentations.

What's interesting to note is that the initial IP rate does not automatically translate into highest rate of return. Other factors such as well cost, royalty burden, gas quality, transportation costs, and basic differential also play a very important role in determining rate of return for each of these shale plays. While we were in the R&D phase of the Marcellus shale play, we provided IP rates for both our vertical and horizontal wells. The IP rates were important as they gave us a rough understanding of the productivity of the wells. More important than IPs, however, is longer term production history, from which we can estimate gross ultimate reserves and projected rates of return. The good news is that based on our first 24 wells, in the Marcellus, we have a play that generates very attractive rates of return. The question is how consistent and repeatable were the Marcellus be over our very large acreage position. To date we have drilled over 100 vertical and horizontal wells in the Marcellus play, which is derisk and a material portion of our acreage. As we continue to ramp up drilling and gain additional information we will hopefully derisk more and more of our large acreage position. Said in a simple way, we know that the Marcellus works in an attractive way in certain areas. The question is, how much of the acreage will drill out.

As we move forward with the developments phase of the Marcellus play, we are providing more and more information as to reserve quantities, well cost, et cetera. And less and less IP information. This is the same M.O. that we used in the Barnett shale project. As we all know well IP data can be calculated in many different ways. It is difficult to compare IP rates calculated by one company to initial production rates calculated by a different company. We believe by providing estimated reserve quantities declining curves, well cost, et cetera, investors will be able to make a more informed decision as to the quality and potential of our Marcellus acreage. From time to time we will continue to provide IP rates for certain wells than we deem newsworthy.

On our Web site we have compared the -- we have posted a slide that compares the Marcellus to the other major shale plays. I want to make it clear that we are not trying to predict the outcome for each of these shale plays. There will be wells drilled by other companies in the other shale place that will be better or worse than our analysis. This is our attempt to broadly compare the plays based on information we have at hand today. In each of the shale place we are where a company's acreage is located is significantly important. The core of each of these place will be far less than the gross play outlined. I strongly cautious that investor does not attempt to hand over a large acreage position of the various companies and assume they are going to be all the same. The definitive way to know how good an acreage block is is to drill the wells and see what the production and decline curves look like.

All in all we believe this information will be helpful and will assist in distinguishing Range from other companies. Most importantly it should give our shareholders a much better feel for the potential we have in the Marcellus play. It's been roughly five years since we drilled our first vertical well; Marcellus well, the Rims number one, and we've come a long, long way since then. I want to give most of the credit to our Marcellus team in Pittsburgh as they are the one's who are making the Marcellus real.

In summary, looking at Range today, we have the largest and highest quality drilling inventory in our history. Our inventory together with our margin plays represent 20 to 28 Tcf of future growth potential. This equates to seven to ten times our existing proved reserves. We are excited about the growth potential of Range. We are also intently focused on delivering each quarter. The second quarter of 2009 is a shining example of this commitment buy all the employees at Range. With that, operator, let's turn the call over for some questions.

Thank you. (Operator Instructions). First question, Tom Gardner of Simmons and Company.

Good afternoon, guys.

Hello, Tom.

I have a few questions related to the Marcellus. Specifically on those 24 wells that went into your type curve. How many of those were below your 4.4 BCF per well average and if you remove the problem wells what impact would that have on your average EUR.

Tom, out of our whole data set the only wells we really removed from that were the first three wells which are our first three attempts and our fourth well was our great success back in August of 2007. And I give the team again great credit for figuring out the play so quickly particularly when you compare that against the Fayetteville, Barnett or Woodford or any of the other shale plays. The results are reasonably consistent cross there. Granted there is some spread but there is a lot of consistency as well. But I couldn't be more excited that, I thought three to four was great and I would still be thrilled with that but the fact that 4.4 B.s and to get economics that are that strong I couldn't be happier with.

I really appreciate your shale play comparison. I just wanted to ask you to kind of fill out the terminal decline rates and perhaps the life of each of those? I'm sure I could back into them but I just wanted to know what you were assuming.

The terminal decline rates we used for each of them was 6% and life of 40 years. Again, the key is ultimately on all these place play is what kind of rate of return does that generate much the shape of the curve, the gas price you get, the royalty, the amount of capital you pay, and then of course rate of return takes into account the discounting the that and again I think for any large scale repeatable play in the US that's about as good as it gets that I'm aware of. And we try to be very fair with all the plays. John said we use public data and Rodney mentioned on all the plays but we try to bias the other plays by the high side by taking the core, best operators and compare it against that.

Thanks for that. And just your thoughts on development plans for your Northeast portion of the Marcellus and your thoughts on the quality of that acreage relative to what you're developing now?

Well, I'm excited about that. Like I mentioned earlier really Range has the best horizontal play which was in the southwest actually peak out at $26 million per day and average over $10 million per day for 30 days. Our best vertical well was actually up in the Northeast and we announced that I don't remember the exact rate but it was over $6 million per day and it was very strong. We are just beginning horizontal drilling up there, our first rig should be on location middle of August, led by the end of August. We will drill two back to back and actually I'm excited about both of the wells because we are offsetting the best vertical well and also another excellent vertical well we also shot 3D over those areas. We are offsetting great verticals wells where areas where we have nice blocking positions and a lot of running room. Time will tell but we should have those results clearly well before the end of the year.

Excellent. Excellent. Any thoughts on your acreage in Roberts in [inaudible] counties with respect to the Granite Wash?

Yes, we have a Granite Wash play up in the Texas panhandle primarily that we are pursuing. Those are good wells. There was big news this morning with the horizontal wells by New Field. We like our -- the stuff we are doing in the mid continent is great. Given the size of the acreage positions we have in repeatability, they are strong economics, strong rates of return but we don't have 900,000 acres like we have in the Marcellus and it's that large scale and repeatability. But the economics of our play up there in the Granite Wash and St. Louis are strong.

Thank you, guys.

Thank you. Our next question comes from the line of Ron Mills with Johnson and Rice, the line is open, you may proceed with your question.

Good afternoon. Tom just asked one question on your Northeast PA development. Any, any additional information in terms of where that well would yield us, like your wells in [inaudible] county.

I think we said that earlier. We are going to start drilling in [inaudible] county. We have a nice acreage position from Bradford down through [inaudible] County and some of the other counties. We haven't specifically put it all out. 350,000 acres is a big position and again we are offsetting some excellent, the best vertical well that I'm aware of in the entire play which is our well.

In your approach looking ahead to 2010 and you have a six rig program, would you still have a predominant amount of your activity in southwest Pennsylvania and would you start concentrating a lot of that activity within that 65% or so of your acreage which has been bounded by industry activity or how would you progress in terms of testing the remaining kind of 150,000 or 175,000 acres in southwest PA that isn't within that industry box you described.

Well, we will be doing three things next year. One will be continuing, really we know it's about driving up production of low cost and driving up production per share and cash flow per share and we are going to do that predominantly in the southwest in that low derisk area. In addition by the independent of next year, by the ends of 2010 we should have take away capacity up in the Northeast. So we will also begin drilling in the Northeast. So we will be doing development drilling up there but a lot of the drilling is going to be down in the southwest. And then if you go to 2011 you will see a significant ramp up in the Northeast as well. In addition, the third thing that we will be doing is continuing to delineate the rest of the acreage so that we understand what we have and where it is. And in that Marcellus and like I mentioned earlier this year we will actually drill two wells by the ends of this year, one for the Utica shale and one for the upper Devonian shales.

Ron, this is John. One thing that's also important when you get a big acreage block like this you have to obviously be cognizant of expiring leases and terms on your leases and what not. The good news is we've got a lot of the acreage held by production so there is no term on it. So that's really good news. And then the next big chunk of our acreage is acreage that has three to ten years left on the term. So we don't have that much acreage in the short term that's going to expire on a relative basis to the 900,000 acres. So, and I think we only have commitment wells two or three commitment, maybe a handful of commitment wells we have to drill over the next 12 months. So that's really going to afford us a lot of flexibility to really put the rigs in places that we know are going to drive up production or in areas where we have big acreage blocks we want still relatively untested that we can go see what's going on and try to get some technical data on those. So we are not being driven by the land so much as just where the opportunities are and what can really drive up our rate of return and our stock price quite frankly.

And when you look at your expected activity levels assuming part of that is dependent on your cash flows, therefore, your, the pricing. To maintain a six rig program through next year, is that 554 that you are putting in a pretty good number that you need to just to fund that kind of program or is --

You got it baby, pretty simple. Yes, we will spend our cash flow and when you run all the numbers, Yes, the 550 by 750 just made sense in terms of not only kind of the way we view the market but also what it takes for us to be able to double the production from exit rate from ends of this year to end of next year. So we feel really good about that as well. And then the obviously just like last year we will, just like this year and last year we will -- Chad and his team will be looking at asset divestitures and whatnot and quite frankly we still have a few little ones that we are working on this year and then we have some other ones we are thinking about for next year and that will just add to that. So we feel really good about our ability to fund the Capex program this and next year given our cash flow and our asset sales that we see down the road. So we feel really good about it. And the other thing is, again, don't want to beat a dead horse here but the capital, I can't be more excited about the impact of the capital efficiency. It sounds trite to say but we are just doing more with less and the reason is we are focused on the things that have the least finding cost, the lowest finding cost. So what it does it just allows you to do more. That coupled, that coupled with the fact that the Marcellus is now going from a little turbobooster versus a drag and plus the fact that you are seeing, we are starting to see some of the full benefits of lower service costs as well so when you take all that into consideration our capital efficiency is really that, to me is the most exciting thing about Range right now is just the capital efficiency and how that drives through your capital budget and everything else you do and how you look at that and look at the Company in terms of value per share and things like that. So that's kind of how we look at it.

Great. Thank you, guys.

Thanks, Ron.

Thank you. Our next question comes from the line of Marshall Carver with Capital One Southcoast. Your line is open. You may proceed.

Thank you, one more question, is the $24.5 million per day well in the type curve has that been on for more than 120 days?

Yes, that well in there and is probably the worst well in there. It's all in there, doesn't significantly drive one well out of 24. The other thing I would like to say, too, and just to clarify that a little bit, I may be partly guilty of driving that. Being my engineering background and the other engineers we have, engineers are nerdy guys. One of the fun things to do when we had that plant come on last October we knew we had an excellent well and what we did is just let that well flow full bore into the plant. We aren't designing our wells going forward to achieve maximum rates. We are looking at maximum rates of return and maximum PVI and NPV. So we aren't so, a lot of the wells in that curve, you could argue are actually rate restricted early but I think you are talking about just change, the shape of the curve a little bit. At the end of the day if we can generate 64% rates of return at $6 gas and under $1 fining cost, I will do that all day long particularly when we have thousands of wells to do it on. So a lot of people get skewed by that. I I have to admit eye somewhat reget a little bit the way we did that because it doesn't, somebody has to question and I will just answer it, we haven't talked about other wells or high rate wells, what does that mean, it just means that we haven't engineered and design them that way. We've drilled excellent wells. We drilled wells recently that have tested $10 million over per day and could have even done more. So it's, you have to remember, for the guys that are engineers in the, that are on this call you can make those wells to some degree as long as you have capacity, whether you produce a well $24 million per day, $15 million, $10 million or $5 million, what you are doing is changing the shape of the curve, not the reserves. And granted it affects rate of return but tater it's about optimizing rate of return, NPV. And as long we can make smart decisions like that that's what we will do. That was a fun engineering experiment.

I mean this is John. I'm not an engineer. I will put my take on it. if you look at what we are doing now, now that we've got the infrastructure built out and we've got compression throughout this, that couple hundred thousand acres that Jeff talked about, in some cases we only have, we don't have the ability to flow these wells at 100% of their capacity when they come online just because we are not designing the take away capacity or the compression to do that because if you did it would just, you would be wasting money. And so we don't think it's, we don't think our shareholders wants to us waste money. We think we want them to maximize the NP V.

So that was a little bit about my whole discussion here about IP rates and I know they are important especially for you all out there that when you see these different plays, the only way to some degree you can tell the difference is look at some of the IPs but I would be really careful when you think about IP rates because they, they are just one little piece of the puzzle and there's a lot more to be, to be looked at when you are looking at that. And again IP rates can vary all over the board by how long it was, what kind of choke, what kind of back pressure you've got on it. There's a gazillion different thing that really impact that. That's, that is the primary reason that we've spent the last couple of, four, five weeks and Al Ferguson and his team to come up with this curve and come up with other stuff is to give our shareholder who I really care about, 100% about is much better feel of what we've got here. And I think the only way of doing it was to get away from the IP rates and really focus on the decline curve and what we think on a primarily basis the gross ultimate reserves are and how that translates in a rate of return. We will continue to update that slide. We will continue to give you all information as those things change. One of the things we are looking at is longer lateral lengths, doing more stages, just like any other plays we are doing that. We had good you can is says on that as well: That could actually increase our well cost but it would, in some cases actually reduce our increase our net present value and reduce our finding cost. There's a lot of thing. We are still tinkering with the dollars to get this right and again over such a large acreage position one thing we learn in the Barnett you can go five to 10 miles away and you have to adjust the dollars a little bit. It's again one of the reasons why we don't have ten or 15 rigs running out. We are taking it "a little bit easy" from some peoples perspective because we want to make sure we do it right. Our view of it is quality not quantity and we did that in the Barnett and we are going to do the same thing in the Marcellus.

Great. Thing. One quick, another quick question, in your IRRs, what's your assumption on cash operating expenses LOE and gathering transportation?

For the Marcellus, when you look at those two numbers combined it's a little bit under $1 then we just use public data for the other three. So if you want the exact details call Ferguson. I think you know him. He will clue you in. The rest of it is just public data. That's our best get at picking public data. Feel free to use whatever public data you want out there. On the Marcellus data we are constant. We try to take the best optimistic reasonable data for those other three plays.

Thank you very much and thank you for the type curve as well.

Thank you. Our next question comes, pardon pronunciation comes from Bijou Perincheril with Jefferies and Company. You may proceed with your question.

We can't hear you on our end.

[inaudible] when I look at it the 19% or so per quarter is a high percentage of what you've been spending historically for acreage. Do you think is that number goes to the level off and going to come down at some point or am I missing something?

This is Rodney, would you repeat the first part of your question or pick up your phone?

Looking at the acreage cost, in $14 million to $19 million that you mentioned still seems like a high percentage of what you spend historically for acreage. I was wondering if that number is going to be coming down in the next few quarters or am I missing something that I'm looking at?

This is Roger. That 19 high-end of an estimate includes just the regular quarterly amortization of your unproved and you are also an assessment for your larger blocks that you look at on an individual basis. You are right, it will change. It will vary overtime with our experience, how many wells we drill and all these other factors that I went through on last quarters call. So it's really, it could go either way but I think that's a good estimate on where we are going to be right now going forward. The other add on as I mentioned was Barnett acreage a couple of big blocks that didn't make sense for us.

Okay. And just so that I understand what goes into that number is or what you are writing off is essentially the pure acreage costs, right, there's no other capital going into that number?

That's right. Just the amount we book for acreage. And back to the one of your original points in your first question, if you take that $19 million amount and divide it into our total unproved property balance you are going to see that that amount tracks very closely with what we've seen from Cabot and EOG in prior quarters.

Okay. Perfect. And then a second question are there a lot of discussion lately about increased regulation of over the counter derivatives market. Do you have any thoughts on how that might affect your hedging strategy going forward?

Well, one, at least what I've seen is the legislation seems to be idiotic to put it plainly. What I understand there's a lot of discussion there and a lot of it's changing as we speak. I think at the end of the day somebody with intelligence will actually look at it and come up with something in makes a lot of sense. I don't think what they wrote they intended and they will figure it out and get there. That's based on some information I just got this morning. I'm hopeful that intelligence and reasonableness takes over and what gets past from that. But who knows.

Okay. And just from my impression your current structure, are you required to make any margin, cash margin payments or do you use your reserves as collateral for hedges?

Yes, we do exactly that. Our hedge portfolio is very diversified among essentially our bank group. We've got 26 banks in our bank group and we've got a number of those are in the credit or some of the big institutions that do a lot on the hedging side. We do have some basic hedges and whatnot with Goldman and a couple of other people that aren't in our credit facilities but they are relatively minor. But over 95% of our hedging book there's no margin.

There's no margin, at all.

Because it's secured under our credit facility which, and that goes both ways as well. The good news is that if those institutions couldn't pay us then we don't pay them on the interest. So, you know, it's, it goes both ways which I think is really important given what we've seen over the last 12 months.

Okay. And then one more question on the Marcellus, is there any production currently coming from the dry gas window out there or is it all being processed?

Yes, the, well, the pretty much everything we have down in the southwest at this point is being processed. We are going to, there is a few exceptions to that and then we are not online in the Northeast yet. That will be at the end of 2010. We drilled some great wells and tested them for 30 days. But we are just starting horizontal drilling and that will be online at the end of next year.

We've got several infrastructure projects that we've actually got going up there in terms of on the dry gas side that I'm very pleased with in terms of progress. As Jeff said we have a great midstream marketing team up there. So they are doing a great job and they are right on schedule and doing everything we've asked them to do. And very experienced. These guys have and gallons have got a lot of experience in the basin. They know all the other big pipeline companies and we've got a lot of really neat infrastructure thing we are working on. So that actually is much better and much more ahead of schedule than I ever would have thought say a year or two ago. So very pleased on that front.

Is that also being done by mark west?

It's all the stuff in the southwest is. There is some other stuff that's not. So, Yes, but that's kind of the way that we intended all along quite frankly.

Okay. That's all for me. Thank you.

Thank you. Our next question comes from the line of Michael Hall with Stifel Nicolaus.

Thanks. Good afternoon. Just kind of keeping on the capital efficiency theme. Wondering if you have any sort of totals as to what you've spent to date in the Marcellus and then along those lines when do you think maybe you will start to turn free cash flow positive? Is that a year out, two years out, five years out, any color there?

I can answer that in a very general way. We've spent roughly $1 billion in the Marcellus. And we've run a lot of models taking the project through depletion in all the different areas, sensitizing rate of drilling and all kind of different thing. It's surprising. It turns free cash positive a lot quicker than you think. When you start running that type curve and model but I don't want to get any more specific than that at this point. Again, the key is I think we are, our goal is to be good stewards of our shareholders money. We have a great project with stronger rates of return at low cost. It's very repeatable. I think we have great places to invest our money in the Marcellus as well as or in the Barnett in some of the stuff up in the mid continue then.

Sure, great. Thanks for that. And then thinking about southwest Pennsylvania region in general, you seem to have a lot of product of your own obviously ramping up and a number of other operators a lot of gas coming in from Rex as well into the region. Any thoughts on locking in differentials there? Have you taken any steps along those lines?

Yes, I mean, we have. What's interesting is that, Yes, there's been a lot of talk about a lot of rates. But probably at the end of this year the Marcellus probably is going to be I would guess $200 million, $250 million per day in total. And so it's going to take a number of years to really make, to make the play in general what I would call material for the industry. That being said, by the end of this year including by the end of next year it's going to be very material to us and that's quite frankly what I care about. I think it's going to take longer, I mean take the Haynesville longer, it's going to take the Marcellus in general just to get all the stuff sorted out. And, you know, again, Rex was on the overall thing just isn't that material. So on the margin, could it affect your basis differentials plus negative $0.10? It probably could but again that's, the way I look at it that's fairly immaterial. We, again, back to what we're doing, we are taking a very aggressive proactive stance in terms of marketing the gas and looking at things. We are looking a lot of end user projects. There's a lot, enormous amount of interest in the Marcellus in that gas in terms of long-term electric generation and a whole lot of other thing. A lot of people have come to us. We are looking at a lot of different opportunities. It's really exciting but we will let our team up there do that. It's really exciting but some of them are years away. But very exciting in terms of some of the thing we are seeing out there in terms of opportunities to sell gas to some very nice customers that actually pay their bills.

Thanks for the color. Appreciate it.

Thank you. Ladies and gentlemen, we are nearing the end of our presentation. We will now go to pardon the pronunciation, [inaudible], Roth Smith Energy Group.

Hey, guys, just a couple quick questions, on the 4.4 Bcf, you guys are expecting over 40 years given that a lot of the wells that you have are from kind of the wet gas area are you guys upticking the volumes or rung the price up with respect to liquids extraction?

We are just running what the current efficiency is off the [cryo] plants in terms of liquid extraction.

Are you, so basically the pricing that you are modeling in would reflect kind of the liquid extraction that you get from it?

Yes.

Okay. And just a second quick question. On that kind of 40-mile by 40-mile area that you guys are talking about in southwest PA I'm guessing that's including Washington and [inaudible], I was just wondering how many wells of kind of the 24 wells that you have production data for have come from more the southern southwest PA acreage and from those southern, and from those wells are they below or meeting the type curve or slightly above?

Well, they are all from southwest PA and they are all inside that box. And that type curve is a summation of all those wells. And there's a distribution like typically you'd see but they are all reasonably consistent within there.

Okay. So specifically in northern Washington have you, can you guys disclose how much acreage you have in northern Washington out of that box?

No, I mean this is, what you've seen us do over time is continue to just throw back more and more layers of the onion, give you more detail. We've done that this time by coming out literally with the actual type curve and our current costs and we will continue to give more and more data but it's also competitive so we are always in that position of, again, we want to be good stewards of our shareholder money but we are all shareholders so it's, the IR guys would also like to give more information because you guys always want more, the technical guys always want to give none because they know it's competitive. We will continue to give more and more data. As we go forward. Hopefully you guys have been pleased with this latest rounds of data. I mean, those are, that actually is our zero time slot our type curve for those wells and like John said we will continue to update those.

Okay. The 80-acre spacing like you just mentioned that based on 80-acre spacing like does it makes sense from kind of the gas in place number, then the 4.4 on 80s or do you think 40s or visits are possible?

You're right, we are looking at a combination of decline curves, we are tying it back to volume metric, we are thinking about what's reasonable. We've done simulations and modeling. I think that's a very reasonable number at this point in time. As we learn more about the Marcellus and more about the formation right on top of it as well as some of the thing below it we will continue to update you on our thoughts on spacing. But hopefully what you saw is the, I mean the 4.4 B.s we think is a very real number. That's literally the average of those wells. Today we are drilling complete notes for $3.5 million generating those kind of rates of return that are shown on the plot. Again if you compare that against any large scale repeatable project out there I think that's as good as it gets and I think our team has done it a great job getting there as quickly as they have. But we are always going to work on optimizing. Like John said we are never going to be happy. We always want to drill higher and higher quality wells and improve our NPV and rates of return and we will continue to experiment and hopefully the guys will improve on that although if they never improve on that and we can just continue to repeat it I will be a very happy guy.

Great. Excellent. Are you guys running like sputter rigs as well to start the hold off?

We drill the straight part of the whole with the smaller rig and then come back the and drill the horizontal part with a bigger rig.

You have three horizontal rigs running?

That's an important point just for clarification. When we say three rigs I'm just counting the big rigs. There's actually three small rigs ahead of those. If you want to count all of them we are running six rigs and six would become 12 so double the big rigs.

And in like.

Don't double the big rigs, the sputter rigs.

Got it. In [inaudible], did you guys take cores on the first few verticals?

We have a lot of data. We have full log suites and ECS logs. We might have some core data off the top of my head I don't remember. I know we have 3D over the areas we are going to be drilling. That's why I feel really good about those drillings. Until you drill them and complete them you don't know but we are offsetting the best vertical well we've drilled off of an existing 3D. That's about as derisk as you can get it will be interest to go see how it goes and time will tell. We'll know in short order. We have a big position up there 350,000 acres. To the extent we have success perhaps those reserve numbers there can be even higher.

You guys have already organized all pipeline right aways and stuff like that.

We bought that. We have our taps. Like John said the guys are staying ahead. We feel comfortable getting it on buy the end of next year. We will have big volumes coming from both the Northeast and Southwest.

Okay. Great. Excellent. That's all I got. Thanks.

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

Thank you, operator. Well, thank you all for everybody for joining us again. Clearly an interesting environment we are in in terms of this industry. I've always said that the cure for low gas prices is low gas prices and I think today's historic number just reflect the fact that we've dropped over 60% of natural gas rigs in the US, it's starting to have an impact. It's just we are walking through the desert here and nobody likes to do it but we will get back to some positive GDP here eventually when the supply side comes down I think gas prices will normalize.

That being said, I've always said it's my advice is you ought to buy Range irrespective of what you think gas prices are. We are not the best predictor of gas prices. We don't think that's our job and quite frankly we don't think we are very good at. What we are good at is driving up production and reserves at low cost. Hopefully to that quartile or better year in and year out. We think that's what really drives rates of return and drives stock price over a period of time.

I know we've given out a lot of information in terms of the Marcellus and I'm sure there's lots of people who have lots of questions about all little details of that. Feel free to call us afterwards and we will get you that data to the extent that that data is available and we will get that you information. Obviously we are going to be, there's a cut-off in terms of competitiveness where we won't give it to you, but some of the thing that we've talked about we will give you some of the details if you've got it. Feel free, a number of you come by the office of late, feel free to come by and we will continue to update you on what we are doing. We are extremely excited about what we've done so far this year. We think we are in the very good position to be able to drive up value even at these low gas prices and in some respects I actually think these low prices have actually been good for us in the Marcellus because it's kind of slowed things down a little bit in terms of acreage competitiveness and it's let us really block up some of the acreage that we probably wouldn't have been able to do otherwise.

At the end of the day we are very well-positioned and we look forward to giving you the third quarter in terms of our results and the progress to date. So thank you very much.

Thank you for your participation in today's conference. Ladies and gentlemen, you may disconnect your lines at this time.