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Executives

Rodney Waller – Senior Vice President

John Pinkerton – Chairman, Chief Executive Officer

Roger Manny – Executive Vice President, Chief Financial Officer

Jeffrey Ventura – President, Chief Operating Officer

Analysts

Thomas Gardner – Simmons & Co.

Ronald Mills – Johnson Rice & Co.

Marshall Carver – Capital One Southcoast

Biju Perincheril – Jefferies & Co.

Michael Hall – Stifel Nicolaus

[unidentified analyst]

Range Resources Corporation (RRC) Q2 2009 Earnings Call July 23, 2009 1:00 PM ET

Operator

Welcome to the Range Resources second quarter earnings conference call. (Operator Instructions) Statements that are made in this 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.

Rodney Waller

Good afternoon and welcome. The results for the second quarter of 2009 leading the consensus number and clearly continuing to execute our business plan for 2009. In trying to be transparent as possible, but still maintain our competitive advantages, Ranger shared a tight 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 shelf plays pulling 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 today are John Pinkerton, our Chairman and Chief Executive Officer, Jeff Ventura, our President and Chief Operating Officer and Roger Manny, our Executive Vice President and Chief Financial Officer.

Before turning the call over to John, I'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's now available on the home page of our website or you can access it using the SEC's anchor system.

Also available on the home page is the slide showing our Marcellus tight curve and comparison of other shale plays. In addition, we've posted on our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBIDAX and 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.

Second, we will be participating in several conferences and road shows in the upcoming weeks. Check our website for a complete listing of those in the next several months. We will be at Enercom's Oil and Gas conference in Denver on August 10 and 11, the Energy Forum in Houston on August 18 and 19 and Barclay's CEO Energy Conference on September 9 and 10 in New York.

Now let me turn the call over to John.

John Pinkerton

Before Roger reviews the second quarter financial results, I'll review the key accomplishments for the second quarter. On a year over year basis, second quarter production rose 14%, meeting the high end of the guidance by almost 10 million a day. This also marks our 26th consecutive quarter of sequential production growth.

The driver for the higher than anticipated production was some exception drilling results both in the Barnett and the Marcellus shelf plates. Our drilling program was on schedule throughout the quarter as we drove 145 wells. We continue to be extremely pleased with the drilling results and in despite the low prices, continue to generate attractive rates of return.

Currently, we've got about 14 rigs running which is down about a half from where we were last year when we had about 30 running. The 14% increase in production was more than offset by a 32% decrease in realized prices. As a result, second quarter financial results were lower than the previous year.

We're most pleased on the cost side as our controllable costs were well in line with expectations. Unit operating costs came in at $0.86 per mcfe. That's 18% lower than the second quarter of last year.

Right at the quarter end we closed the sale of our Furman 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've said before, we view asset sales as a way to fund our capital program, hydrate our asset base, maintain our 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 Furman sale.

With regard to our Marcellus self plate, significant headway was made in the quarter as we continue drill some terrific wells, hydrate our acreage position, build out infrastructure and bring down our oil cost. In addition, we continue to add some high quality technical personnel to our growing Marcellus team in Pittsburg, 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'll turn the call over to Roger to review our financial results.

Roger Manny

The second quarter of 2009 bears many similarities to the first quarter this year as oil and gas production set a new record high, up 14% from the second quarter of last year. Direct operating costs were down significantly and our liquidity and balance sheets 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 derivatives totaled $244 million, 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, upward costs were significantly lower this quarter; in fact, the lowest since 2007. Cash flow for the second quarter of '09 was $156 million. That's 29% below the second quarter of 2008. Cash flow per share for the quarter totaled $0.98, $0.02 per share higher than the analysts' consensus estimate of $0.96.

Quarterly income tax of $185 million was 25% 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. While 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 market loss in the second quarter compared to a loss of $162 million last year. Another non cash revenue item worth mentioning is a $4.6 million loss on our equity investment primarily at 50% investment in an Appalachian drilling company.

Skipping to the bottom line for a minute before discussing our cost performance, quarterly earnings are calculated using analyst's consensus methodology in the second quarter of this year were $34 million or $0.21 per fully diluted share. That's $0.03 higher than the analyst's consensus of $0.18.

The GAAP net loss for the quarter was $40 million compared to a net loss of $32 million last year. As Rodney mentioned, the Resources website contains a full reconciliation of these non-GAAP measures including cash flow and EBIDAX in cash margins.

The expense categories for the second quarter of '09 reveal the impact of lower oil and gas prices as a resulting reduced demand for services. Cash direct operating unit cost was $0.86 per mcfe in the second quarter of '09. That's $0.07 lower than the first quarter 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, and 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 oil taxes per mcfe were 53% lower than last year's second quarter and that reflects lower oil and tax prices. Production taxes totaled $0.19 per mcfe for the second quarter of '09. That's compared to $0.46 last year. We expect 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 $0.01 from last quarter and up $0.02 from the second quarter of last year. The area where G&A expenses are 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 is anticipate to be in the $0.53 to $0.56 per mcfe range for the rest of '09 as 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 $0.0o6 from the $0.69 figure last year. The extra pressure on interest expense stems from our decision to refinance $300 million in short term floating rate bank debt with longer term fixed 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 with the reductions being evenly split between lower drive home costs and lower seismic expense. That's somewhat unusual in this business even for Range that had not drive holes in the entire quarter as we did this quarter, but expect exploration expense to return probably to the $12 million to $14 million range per quarter for the rest of the year.

Depletion, depreciation and amortization per mcfe for the quarter was $2.25, even with the first quarter 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 our other assets. Our DD&A rate should remain at or just 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 abandoned process works, and I stated that the expense figure would continue to vary quarter to quarter and our best estimate of future quarterly non cash expense was in the $16 million to $19 million range.

Since the second quarter of 2009 impairment and abandonment figure was $41 million, the first half of my prediction about the number varying was clearly correct, but the second half was off. $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 provision for specifically identified leases that we believe should be impaired by some current economic conditions.

Because so many of you have asked questions about this unproved property process and the 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 this successful method of accounting for oil and gas properties. This is significant in that there are major differences in how these accounting methods treat the disposition of undeveloped leasehold, or what accountants call unproved properties. One difference is that delay rental and other costs to hold unproved properties are expensed under successful efforts but capitalized under full cost.

The more 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 hole drilled 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 the impairment against earnings.

Full cost producers on the other hand do not expense the impairment even if the property is 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 costs 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 accounting method handles dry holes. They're not expensed as they occur, but amortized over time as part of the full cost pool.

The day of reckoning for full costers 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. The 10 full cost shale companies posted an aggregate pre tax ceiling test impairment at year end '08 of $27 billion and an additional $25 billion in the first quarter.

Embedded in this $52 billion of write offs are previously capitalized dry holes and impaired acreage. These non cash charges are largely ignored by investors as an inevitable by-product of the full cost accounting rules, yet because so few shale players use the successful efforts accounting, similar yet much, much smaller non cash impairments seen unusual and out of place.

Southwestern Energy for example, a full cost company we admire greatly that has shown to everybody how to properly execute a shale play had a $907 million pre tax property impairment in the first quarter this year. So 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 would continue an unproved property impairment, must have inferior acreage to a full cost company without such impairments, or that acreage impairment by a successful efforts company should be treated differently than a ceiling test write down by a full cost company.

This is clearly not the case. There are two companies besides Range that are significant shale players and use the successful efforts accounting method. They're EOG and Cabot. There are $41 million provision for unproved properties this quarter if consistent with historical impairment figures reported by these other companies.

We continue to believe that the totally provision for unproved property impairment will run in the $16 million to $19 million range but this amount will vary based on a myriad of factors many of which remain outside of our control.

Range recorded a benefit of $23 million in deferred taxes for the second quarter and we recorded $619,000 in State level cash income taxes, and while producing no book gain or loss, the successful sale of the Furman properties resulted in an approximate gain for tax purposes of $140 million.

Range will shield this gain using deductions from this year's drilling program such that our $160 million NOL carry forward will not be reduced. Range is essentially fully hedged for the remainder of '09, with approximately 80% of our gas production hedged at the full price of $7.49 per mbpu.

Early in the second quarter of this year, we began to layer in hedges on our 2010 gas production. We now have collars in place covering approximately 47% of the first half of 2010 production at the full price of $5.50 per mbpu and a ceiling of $7.44. We have approximately 24% of our second half 2010 production hedges at collars of $5.50 by $7.50 per mbpu.

There are several good news items from the balance sheet this quarter as we ended the quarter with a lower debt to cap ratio than we started, and we successfully achieved $300 million on 10 year, 8% senior sub notes at a yield of 8 3/4. As a measure of Range's standing in the credit markets, these notes have been the only 10 year note qualified notes issued by a high yield A&P company this year, and we're the first 10 year note qualified subordinated notes issued by any high yield issue in any industry this year.

The 8 3/4% yield is the lowest that any year to day 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 Furman asset sale reduced our bank debt balance to $403 million, down from $807 million at the end of the first quarter.

The $403 bank debt balance provides Range with over $1 billion in unused borrowing base capacity and approximately $850 million from liquidity.

Looking back on the second quarter of '09, Range delivered better than expected operating results, and another double digit quarter of production growth and significantly lower operating costs. 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 cushion; both good things to accomplish in this business environment.

John, I'll turn the call back to you.

John Pinkerton

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

Jeffrey Ventura

I'll begin by reviewing production. For the second quarter production averaged 444 million cubic feet equivalent 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 Furman properties right at the end of the second quarter so our net volumes in the third quarter will be reduced by about 15 million per day.

I'll begin the operating update with the Marcellus shale and the Appalachian basin. To date, Range has drilled and completed 46 horizontal Marcellus shale wells. 41 of those wells are currently online and today we're producing over 50 million cubic feet equivalent per day net.

24 of those wells have been producing for more than 120 days and some for almost two years. Utilizing these 24 wells for the first time, we've released what our tight curve is for the average expected ultimate recovery of these wells. The expected gross ultimate recovery for this 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. Through a wet gas case, after processing the btu content of the gas is 1,150. We currently get paid for the btu's, therefore our gas price is NYMEX times 9.15 plus $0.28 since this gas still receives a premium for NYMEX because of it's location in the Appalachian basin. Our average royalty here is 15%.

Economics for Range's average southwest Pennsylvania Marcellus shell well 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 adjustments and assuming a $5.00 premium btu gas price, results in a 50% rate of return and a cost of find and develop of $0.95 per mcfe. At $7.00 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, I've stated that the average reserve expectation across our acreage position is in the three to four bcfu range. To day, our average well has been about 4.4 bcfe which is above the top end of that range.

I must caution that more wells and more production are necessary to determine what the actual number will be. We're still very early in the development of this play. For now, I'm still comfortable with the three to four bcfu range for the expanse of our acreage.

In the southwestern part of the play we have approximately 550,000 net acres. To date we have drilled and complete 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 southernmost horizontal Marcellus shell wells in southwest Pennsylvania is 40 miles. The distance between our eastern and westernmost horizontal shell well in southwestern Pennsylvania is 41 miles. Within this box we have 173,000 net acres or 32% of our 550,000 net acres in the part of the play.

Of course we feel very strongly 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 industry's northern and southernmost wells is 81 miles. The industry's easternmost and westernmost 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 derisk even more of Range's acreage.

Using just the 380,000 net acres within this low risk, high chance of success area, in essence the derisk box and assuming 80% of the acreage is ultimately drilled, and assuming 80 acres facing, we can potentially drill 3,800 horizontal wells. Assuming 3.5 tcfe per well, that's 13.3 tcfe growth or 11.3 tcfe net unrisk reserve potential for Range.

Range is currently a 2.7 tcf company; therefore we have the potential to grow significantly from just this play and just this area. Importantly, the rate of return on this capital expenditure is exceptional.

In the part of the play, we have an additional 350,000 net acres. This represents another five to seven tcfe of unrisk reserve potential for Range. By the end of August, we'll be studding 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 shoal and upper Livonia shale on portions of our acreage. We currently plan to spud two horizontal wells to test each of these concepts by year end. At year end 2007, Range's Marcellus production was about either 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 and 100 million a day and we currently plan on doubling that to 180 to 200 million per day by 2010.

Future growth beyond that looks very encouraging. By late this year, early next year, we expect to have 200 million a day in process and capacity. We've just recently announced adding an additional 120 million per day of process and capacity which will bring our total capacity when installed, up to 320 million per day.

We have a first class mid stream and marketing group and I'm confident that they'll keep ahead of our drilling team.

I wanted to take some time to discuss our capital efficiency, where we've been in the past and where I believe we'll be in the future. According to a Bank of America study, considering the all in cost structure, Range has either been the lowest cost producer in our peer group or the second lowest cost producer for the last five years in a row.

When Range was first, Southwestern was second. When Range was second, Southwestern was first. The five year time frame that I'm referring to here is 2004, 5, 6, 7 and 8. Today, Range's top three projects are the Marcellus shale, and the Barnett shale. Over the last five years, these projects played a very different role than the role they'll play 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 Marcellus was in 2004. Our early efforts involved pioneering deploying, exploratory and delineation drilling, experimentation, data gathering and acquiring land.

Once we found commercial gas, we began to go up a learning curve and finding ways to improve production and reserves and just recently, this year in particular, began to drive down costs. 2009 is a watershed year for us and as the first major processing plant that was installed in late 2008, allowing us to begin development pad drilling this year.

Pad drilling, coupled with new specially designed rigs allowed us to achieve development wells 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 premier shell play with what we believe are the best economic and largest upside of any upside in the United States, or for that matter, in the world.

Going forward, the low F&B, low LOE and premium to NYMEX to keep Range in the best or one of the best low cost high organic growth companies in the business.

The same is true of our other two plays, the Barnett shell 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 references previously, the first three years, 2003, 4, 5 and 6, included zero or minimal impact from the Barnett.

The last two years, 2007, 2008 did include Barnett drilling, and included in that was our effort to push the play south into southern Johnson County and further south in Hill County in an effort also to 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 areas have a significantly higher F&B cost and significantly lower rate of return than the core of the Barnett. Beginning in 2009, all of Range's drilling will be in the core. This area has a much lower cost structure and therefore we expect the next five years will have a much better cost structure going forward that the previous five years.

We have over 1,000 locations left to drill in the core. 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 are included in 2005, 6, and 7, it was at 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 horizontal drilling technology. We expect the drilling to tight gas and shale's 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 get 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 spend significant capital in Furman, Conger, Clayton and Madonna type gas sands, and the Gulf Coast, etc.

This year in 2009, 90% of our capital is going into the Marcellus, Nora or the Barnett shell. These three plays have a significantly higher rates of return, significantly lower F&B and LOE, have better rate growth than any of other projects listings 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&B costs for these three properties ranges from about $1.00 to $1.50 and 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 U.S.

Range has consistently delivered top 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 core cost structure or better and in addition, consistently building and hydrating our inventory coupled with one of the best teams in the industry.

Range today has more upside and lower risk upside than at any time in the company's history. With our inventory, we have the opportunity to grow the company more than ten fold primarily from the Marcellus shale and lower end of Barnett shale.

We believe our excellent organic growth combined with an excellent cost structure will result in continuing to create strong shareholder returns over time.

Back to you John.

John Pinkerton

Thanks Jeff. That was a terrific update. Now let's look ahead a bit.

Looking to the second half of 2009, we see continued strong operating results. For the third quarter we're looking for production to average 430 to 435 million a day, representing an 11% increase year over year.

The third quarter will reflect the full impact of the sale of our Furman field which we closed on the last day of the second quarter. Furman produced approximately 15 million a day net, so due to the timing of the Furman 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 Furman was clearly the right thing to do, especially given the 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'll achieve double digit production growth again this year, even after taking into account the asset sale and a much lower capital budget.

Given our reduced capital program, we are focusing over 90% of our CapEx Jeff mentioned in the Marcellus, Nora and the Barnett plays. These three plays generate attractive rates of return even at low gas prices.

We are fortunate that the remaining properties in our portfolio have only shallow decline curve. In particular, our gas and CBM properties in Appalachia are in decline at less than 10%.

One of the key elements that had a very positive impact on our results this year relates to the capital efficiency. In the past, we've spent considerable capital on the Marcellus without seeing much return and as Jeff mentioned, in October of last year this all changed as the first phase of infrastructure was completed and production began to ramp up.

As the Marcellus production continues to ramp us 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 $166 million of operating cash flow. So for the full year 2009, our cash flow and completed asset sales will be more than adequate to fund our capital program.

Lastly, I want to spend a few minutes discussing the Marcellus shell play. In our operations news release that we put out a few weeks ago, and as Jeff talked about, we announced 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 indicates gross ultimate reserves for these 24 wells will average 4.4 bcfe. Given how early in the play, we 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 is your acreage is located is extremely important.

We have also provided an updated well cost number of $3.5 million for pad drilling in southwest Pennsylvania. We also posted on our website a slide that shows not only the decline 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're generating in the Marcellus. Using a $6.00 NYMEX gas price held flat forever, adjusting for base differentials, Marcellus drilling projects 64% rate of return and Jeff also gave the number at $5.00 and $7.00.

This 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 these shell plays drill out, this is our best estimate given the public data that is currently available and looking at other company's 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 cost and basic differential also play a very important role in determining rate of return for each of the shell plays.

While we were in the R&D phase of the Marcellus shell 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 in IP's 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 will the Marcellus be over those very large acreage position.

To date we've drilled over 100 vertical and horizontal wells in the Marcellus 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 area. The question is, how much of the acreage will drill out.

As we move forward with the development of the Marcellus play, we're providing more and more information as to reserve quantities, well cost, etc. and less and less IP information. This is the same MO that we used in the Barnett shell project.

As we all know, well IP data can be calculated in many different ways. It's 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, decline curves, well cost etc., investors will be able to make a more informed decision as to the quality and the potential of our Marcellus acreage. From time to time we'll continue to provide IP rates for certain wells as we deem newsworthy.

On our website we've posted a slide that compares the Marcellus to the other major shell plays. I want to make it clear that we're not trying to predict the outcome for each of these shell plays. There will be wells drilled by other companies in the other shell plays 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 shell plays, where a company's acreage is located is critically important. The core of each of these plays will be far less than the gross play outline. I strongly caution investors, do not attempt to hand over a large acreage position of the various companies and assume they are going to be the same.

The definitive way to know how good an acreage block is is to drill the well and see what the production and see what they 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 Marcellus vertical well, the Range 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 Pittsburg as they're the ones that are making the Marcellus real.

In summary, looking at Range today, we have our largest and highest quality drilling inventory in our history. Our inventory together with our emerging plays; represent 20 to 28 pcf of future growth potential. This equates to seven to ten times our existing crude reserves.

We're excited about the growth potential of Range. We're intently focused on delivering each quarter. The second quarter of 2009 is a shining example of the commitment by all the employees at Range.

With that, let's turn the call over for some questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Thomas Gardner – Simmons & Co.

Thomas Gardner – Simmons & Co.

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

Jeffrey Ventura

Out of our whole data set, the only wells we really removed from that were the first three wells which were our first three attempts and our fourth well was our great success back in August of 2007, and give the team again great credit for figuring out the plays so quickly, particularly when you compare that against the Barnett or any of the other shell plays.

The results are reasonably consistent across there. Granted there is some spread but there's a lot of consistency as well. But I couldn't be more excited. I thought three or four B's was great and I'd still be thrilled with that, but the fact that these wells are 4.4 B's and get economics that are that strong, I couldn't be happier with.

Thomas Gardner – Simmons & Co.

I really do 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.

Jeffrey Ventura

The decline rates we used for each of them was 6% and life of 40 years. And again, the key is ultimately on all these plays, what kind of rate of return does that generate? The shape of the curve, the gas price you get, the royalty, the cap you pay and then of course rate of return takes into account the discounting of that and again, I think for any large scale repeatable play in the U.S., that's about as good as it gets that I'm aware of.

And we tried to be very fair with all the plays. Like John said, we just use the public data Rodney mentioned on the other three plays, but we tried to bias the other plays to the high side by taking the core, best operators and compared it against that.

Thomas Gardner – Simmons & Co.

And 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.

Jeffrey Ventura

I'm excited about that. Like we mentioned earlier, the best Range has the best horizontal well which is in the southwest actually peaked out at 36 million per day on average, over 10 million per day for 30 days. Out 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 a day and it was working very strong.

We're just beginning horizontal drilling up there. Our first rig should be on location middle of August, by the end of August. We'll drill two back to back, and actually we're excited about both of the wells because we're offsetting the best vertical well and also another excellent vertical well.

We've already shot three 3-D over those areas so we're offsetting great vertical off of existing 3-D's in areas where we've got nice blocky positions and a lot of running room. Time will tell, but we should have those results well before the end of the year.

Thomas Gardner – Simmons & Co.

Any thoughts on your acreage in Robertson County with respect to the Granite Wash?

Jeffrey Ventura

We have the Granite Wash play up in the Texas Panhandle primarily that we're pursuing. Those are good wells. There was big news this morning with the horizontal wells by Newfield. The stuff we're doing in the mid continent is great. Given the size of the acreage positions we have and repeatability, they're strong economics, strong rates of return, but we don't have 900,000 acres like we have in the Marcellus with that large scale and repeatability.

But the economics of our plays up there in the Granite Wash in St. Louis are strong.

Operator

Your next question comes from Ronald Mills – Johnson Rice & Co.

Ronald Mills – Johnson Rice & Co.

Just one question on your northeast PA development, any additional information on where that well was drilled?

Jeffrey Ventura

I think we said that earlier. We're going to start drilling in Lycoming County.

John Pinkerton

We have nice acreage position from Bradford down into Lycoming and into some of the other counties there. We haven't specifically put it all out, but 350,000 acres is a big position. And again, we're offsetting some excellent, the best vertical wells that I'm aware of in the entire play which is our well.

Ronald Mills – Johnson Rice & Co.

As you approach looking ahead to 2010 and 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 ahs been bounded by industry activity or how you progress in terms of testing the remaining 150,000 to 175,000 acres in southwest PA that isn't within that industry box that you described?

John Pinkerton

We'll be doing three things next year. One will be continuing, really we know its about driving up production at low cost and driving up production per share and capital per share and we're going to do that predominantly in the southwest in the low derisk area.

In addition, by the end of next year, by the end of 2010, we should have take away capacity up in the northeast, so we'll also begin drilling in the northeast. But we'll be doing development drilling up there. A lot of the drilling is going to be down in the southwest. And then if you go to 2011, you'll see a significant ramp up in the northeast as well.

In addition, the third thing that we'll be doing is continuing to delineate the rest of the acreage so that we understand what we have and where it is. And if that's in the Marcellus, and like I mentioned earlier, this year we'll actually drill two wells by the end of the this year, one for the Utica shale and one for the upper shale's.

John Pinkerton

I think one thing that's also important, when you get a big acreage like that; you've got to obviously be cognizant of expiring leases and terms on your leases and what not. The news is, we've got a lot of acreage is held by production so there is no term on it so that's really good news.

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 wells to the 900,000 acres. So I think we only have commitment wells, two or three commitments, maybe a handful of commitment wells that 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 that we've got big acreage lots that are still relatively untouched that we can go see what's going on and try to get some technical data on those.

We're not being driven by the land so much. It's just where the opportunities are and what can really drive up our rate of return and our stock price quite frankly.

Ronald Mills – Johnson Rice & Co.

When you look at your expected activity levels, I'm assuming part of that is dependent on your cash flows, therefore the pricing. To maintain a six rig program through next year is that $554 million that you're putting in a pretty good number that you need to fund that kind of program?

John Pinkerton

You've got it. It's pretty simple. We'll spend our cash flow and the 550 by 750 just made sense in terms of not only in the way we view the market but also what it takes for us to be able to double the production from the end of this year to the end of next year. So we feel really good about that as well.

Obviously just like last year, just like this year and last year, Ted and his team will be looking at assets and divestitures and what not and I think we've still got a few little ones that we're working on this year and then we've got some other ones that we're 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 the asset sales that we see down the road. So we feel really good about. And the other things is, and 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 it, but we're just doing more with less, and the reason is, we're focused on the things that have the least finding cost so what it does is allows you to do more. That coupled with the fact that the Marcellus is now going from a little turbo boost to reverse the drag, and plus the fact that you're seeing, we're 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.

Operator

Your next question comes from Marshall Carver – Capital One Southcoast.

Marshall Carver – Capital One Southcoast

Is the 24.5 million a day well in the tight curve? Has that been on for more than 120 days?

Jeffrey Ventura

Yes. That well in there as is probably the worst well in there. It's all in there. It doesn't significantly drive it as one well out of 24.

The other thing I'd 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 is when we had that new plant come on last October, we knew we had an excellent well and what we did was just let that well flow full bore into the plant.

We aren't designing our wells going forward to achieve maximum rates. We're looking at maximum rates of return and maximum PBI and MPV. So a lot of the wells in that curve, you could argue are actually restricted early, but I think you're talking about this changing the shape of the curve a little bit.

At the end of the day, if we can generate 64% rates of return at $6.00 gas and under $1.00 finding cost, I'll do that all day long, particularly when we've got thousands of wells to do it on. So a lot of people get skewed by that. I have to admit I somewhat regret a little bit when we did that because somebody asks a question and I'll just answer it.

When you haven't talked about other wells or high rate wells, what does that mean? It just means that we have an engineered and designed them that way. We drilled excellent wells. We've drilled wells that recently have tested a 10 million and over per day and could have even done more. So you've got to remember for the guys that are engineers 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 a day, 15, 10 or five, what you're doing is changing the shape of the curve, not the reserves.

And granted it affect rate of return, but at the end of the day it's about optimizing rate of return, MPV and as long as we can make smart decisions like that, that's what we'll do. That was a fun engineering experiment.

John Pinkerton

I'm not an engineer. I'll put my take on it. If you look at what we're doing now, now that we've got the infrastructure built out and we've got compression throughout 2,000 acres that Jeff talked about, in some cases we don't have the ability to flow these wells at 100% of their capacity when they come on line just because we're not designing the take away capacity or the compression to do that.

If you did, you'd be wasting money. So we don't think our shareholders want us to waste money. We think we want to maximize the MPV. So that was a little bit about my whole discussion about IP rates. And I know they're important, especially for you all out there that when you see these different plays, the only way to some degree you can tell the different is look at some of the IP's.

But I'd be really careful when you think about IP rates because they're just one little piece of the puzzle and there's a lot more to be looked at when you're looking at that. And again, IP rates can vary all over the board by how long it was, what kind of shelf, what kind of back pressure you've got on it. There's a gazillion different things that really impact that.

That is the primary reason that we spent the last four or five weeks and Al and his team to come with this curve and do all this other stuff, is to really give our shareholders who I care 100% about, a 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 preliminary to what the ultimate reserves are and how that translates into a rate of return.

We'll continue to update that slide. We'll continue to give you information as those things change. One of the things we're looking at is longer lateral links, doing more stages. Just like in the other plays we're doing that. We've had good success on that as well. And that could actually increase our well costs but in some cases would actually increase our net present value and reduce our finding costs.

So there's a lot of things. We're still tinkering with the valve to get this right and again, over such a large acreage position, one thing we learned in the Barnett, you can go five to ten miles away and you'd have to adjust the valves a little bit. So again, one of the reasons why we don't have 10 or 15 rigs running right now, we're taking it "a little bit easy" from some people's perspective, because we want to make sure we do it right.

And our view of it is, quality not quantity and we did that in the Barnett and we're going to do the same thing in the Marcellus.

Marshall Carver – Capital One Southcoast

In your IRR's, what's your assumption on cash operating expenses, LOE and gathering transportation?

Roger Manny

For the Marcellus when you look at those two numbers combined it's a little under $1.00 and then we just used public data for the other three. If you want the exact details, call Parkerson later on. I think you know him. He'll key you in better. The rest is just public data.

That's just our best guess at taking public data. Feel free to use whatever public data out there but our Marcellus data, we're confident. We just tried to take the best most optimistic reasonable data for those other three plays.

Operator

Your next question comes from Biju Perincheril – Jefferies & Co.

Biju Perincheril – Jefferies & Co.

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

Roger Manny

That $19 million, high end of the estimate includes just the regular quarterly amortization of your unproved and also an assessment for your larger blocks that you look at on an individual basis. And you're right. It will change. It will vary over time with our experience, how many wells we drill and all these other factors I went through on last quarter's call.

I think that's a good estimate on where we're 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.

Biju Perincheril – Jefferies & Co.

What goes into that number of what you're writing off, especially the pure acreage cost, right? There's not other capital going into that number?

Roger Manny

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

Biju Perincheril – Jefferies & Co.

There's a lot of discussion lately about increased regulation over the counter derivatives market. Do you have any thoughts on how that might affect your hedging strategy going forward?

John Pinkerton

One, what I've seen is the legislation seems to be idiotic to put it plainly. But as I understand it there's a lot of discussion there and a lot of exchanging as we speak. I think at the end of the day, somebody with intelligence will actually look at it and come with something that makes a lot of sense. I don't think what they wrote they intended and intelligence and reasonableness takes over and what gets passed from that, but who knows?

Biju Perincheril – Jefferies & Co.

Your current structure, are you required to make any margin, cash margin payments or do use the reserves as collateral for hedges?

John Pinkerton

We do exactly that. Our hedge portfolio is very diversified essentially among our bank group. We've got 26 banks in our bank group and we've got a number of those are in the credit, are some of the big institutions that do a lot on the hedging side. We do have some basic hedges with Goldman and a couple of other people that aren't in our credit facility, but they're relatively minor.

Over 95% of hedging book, there's no margin, because it's secured under our credit facility. And that goes both ways as well. The good news is those institutions can't pay us when we don't pay them on the interest, so it goes both ways which I think is really important given what we've seen over the last 12 months.

Biju Perincheril – Jefferies & Co.

On the Marcellus, is there any production currently coming from the dry gas window up there or is it all being processed?

Jeffrey Ventura

Pretty much everything we have down in the southwest at this point is being processed. There's a few exceptions to that. And we are not online in the northeast yet. That will be at the end of 2010. We've drilled some great wells and tested them for 30 days, but we're just starting horizontal drilling and that will be online at the end of next year.

John Pinkerton

We've got several infrastructure projects that we've actually got going up there in terms of the dry gas side that I'm very pleased with in terms of the progress. We've got a great marketing team up there, so they're doing a great job and they're right on schedule doing everything we've asked them to do. And very experienced, these guys and gals, they've got a lot of experience in the base and they know all the other big pipeline companies and we've got a lot of really neat infrastructure things we're working on.

So that actually much better, much more ahead of schedule than I would have ever though a year or two ago, so very pleased on that front.

Biju Perincheril – Jefferies & Co.

Is that also being done by Marquest?

John Pinkerton

All the stuff in the southwest is. There's some other stuff that's not. But that's kind of the way we intended it all along, quite frankly.

Operator

Your next question comes from Michael Hall – Stifel Nicolaus.

Michael Hall – Stifel Nicolaus

Keeping on the capital efficiency theme I'm wondering if you have any totals as to what you spent to date in the Marcellus and when do you think you'll start to turn free cash flow positive? Is it a year out, two years out, five years out, any color there?

Roger Manny

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 greater drilling and all kinds of different things. It's surprising. It turns free cash positive a lot quicker than you think when you start running that tight curve and model that we put out there.

But I don't want to get any more specific than that at this point. But again, our goal is to be good stewards of our shareholders money. We've got a great project with strong rates of return at low cost that's very repeatable, so I think we've got great places to invest our money in the Marcellus as well as the Nora.

Michael Hall – Stifel Nicolaus

Thinking about the southwest Pennsylvania region in general, you seem to have a lot of production of your own ramping up and a lot of other operators, a lot of gas coming in to the region. Any thoughts of locking in differentials there? Have you taken any steps along those lines?

John Pinkerton

We have. What's interesting is that there's been a lot of talk about a lot of rates, but probably at the end of this year, the Marcellus probably is I would guess, 200 million to 250 million a day in total. So it's going to take a number of years to really make the play in general what I call material for the industry.

That being said, by the end and clearly by the end of next year, it's going to be very material to us, and that's quite frankly what I care about. But I think it's going to take longer. It's going to take the Haynesville longer. It's going to take the Marcellus in general just to get all this stuff sorted out.

On the margin, could it affect your basic differentials, yes, plus or negative $0.10. It probably could, but again the way I look at it, that's fairly immaterial. But again, back to what we're doing, we're taking a very aggressive proactive stance in terms of the market and the gas and looking at things and we're looking at a lot of end user projects.

There's an enormous amount of interest in the Marcellus and that gas in terms of long term electric generation and a whole lot of other things. A lot of people come to us. We're looking at a lot of different opportunities. It's really exciting. But we'll let our team up there do that.

They're really exciting, but some of them are years away, but very exciting in terms of some of the things we're seeing out there in terms of opportunities to sell gas to some very nice customers that actually pay their bills.

Operator

Your next question comes from Unidentified Analyst

Unidentified Analyst

On the 4.4 bcf you are expecting over 40 years, given that a lot of the wells you have are from the wet gas area, are you up ticking the volumes or running the price up with respect to the liquid extraction?

Jeffrey Ventura

We're just running with the current efficiency off the cryo plants in terms of the liquid extraction.

Unidentified Analyst

So basically your pricing that you're modeling in would reflect the liquid extraction that you get from it.

Jeffrey Ventura

Yes.

Unidentified Analyst

On that 40 mile by 40 mile area that you're talking about in southwest PA, I'm guessing that's including Washington, how many wells of the 24 wells that you have production data for have come from more the southern PA acreage and from those wells, are they below or meeting the tight curve or slightly above?

Jeffrey Ventura

They're all from southwest PA and they're all inside that box. That tight curve is the summation of all those wells. There's a distribution like typically you'd see but they're all reasonably consistent with there.

Unidentified Analyst

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

Jeffrey Ventura

No. What you've seen us do over time is continue to peel back more and more layers of the onion, give you more and more detail. We've done that again this time by coming out literally with the actual tight curve of those wells in our current cost and we'll continue to get more and more data, but it's also competitive so we're always in that position of again, we want to be good steward of our shareholder money. We're all large shareholders. It's the bulk of our net worth so the IR guys would always 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. But we'll continue to give more and more data as we go forward. Hopefully you guys have been pleased with this latest round of data. That actually is our zero time slot, or "our tight curve" for those wells and like John said, we'll continue to update those.

Unidentified Analyst

The acre spacing, you just mentioned that 80 acre spacing, does it make it sense from the gas in place numbers and the 4.4 on 80 or do you think laying out 40's or 50's are possible?

Jeffrey Ventura

You're right. We're looking at a combination of decline curves and tying it back to volume metrics. We're thinking about what's reasonable. We've done more simulation 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 formations that's right on top of it as well as some of the things below it, we'll continue to update you on our thoughts on spacing.

But hopefully what you saw is the, 4.4 B's is what we think is a very real number. That's literally the average of those wells today. We're drilling for 3.5 million and generating those kinds of rates of return that are shown on the plotting, and again I think if you compare that to any large scale repeatable project out there, I think that's as good as it gets and I think our team's done a great job getting there as quickly as they have.

But we're always going to work on optimizing. Like John said, we're never going to be happy. We always want to drill higher and higher quality wells and improve our MPV and rates of return and we'll 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'll be a very happy guy.

Unidentified Analyst

Are you running other rigs as well to start the hole off?

Jeffrey Ventura

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

Unidentified Analyst

So you have three horizontal rigs running.

Jeffrey Ventura

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 so if you want to count all of them, we're counting six rigs and six would become 12, so double the big rigs. Don't double the big rigs.

Unidentified Analyst

In Lycoming, did you take cores on the first few verticals?

Jeffrey Ventura

We have a lot of data. We've got full log suites and EKES logs. We might have some core data. Off the top of my head I don't remember. I know we have 3-D over the areas we're going to be drilling. That's why I feel really good about those wells. Until you drill them and complete them your never know. Great vertical wells, those are the best vertical wells we've ever drilled off an existing 3-D so that's about as derisk as you can get.

It will be interesting to see how it does and time will tell. We'll know in short order. We've got a big position up there, 350,000 acres so to the extent we have success, perhaps those reserve number there can be even higher.

Unidentified Analysts

And you've already organized the pipeline right of ways and stuff like that?

Jeffrey Ventura

We've bought that. We have our taps. Like John said, the guys are staying ahead. I feel comfortable getting on by the end of next year. So we'll have big volumes eventually coming from both the northeast and the southwest.

Operator

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

John Pinkerton

Thank you all 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 reflects the fact that we've dropped over 60% of natural gas rigs in the U.S. It's staring to having an impact.

We're walking through the desert here. Nobody like to do it, but we'll get back to some positive GDP here eventually and the supply side comes down I think gas prices will normalize. That being said, I've always said, it's my advice you ought to buy rings irrespective of what you think gas prices are.

We're not the best predictor of gas prices. We don't thing that's our job, and quite frankly we don't think we're very good at it. What we're good at is driving up production land reserves at low cost year in and year out. We think that's what really drives rates of return and our 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 have lots of questions about all the little details of that. Feel free to call us afterward and we'll get you that data to the extent that data is available, and we'll get you that information.

There's a cut off in terms of competitiveness where we won't give it to you, but some of the things we talked about, we'll give you some of the details if we've got it. Feel free. We've had a number of you come by the office of late. Feel free to come by and we'll update you on what we're doing.

We're extremely excited about what we've done so far this year. We think we're in a very good position to be able to drive up value even at these low gas prices, and in some respect I think that low prices has 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.

So at the end of the day, we're very well positioned and we look forward to giving you in the third quarter our results and progress to date. So thank you very much.

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Source: Range Resources Corporation Q2 2009 Earnings Call Transcript
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