山脈資源 (RRC) 2007 Q2 法說會逐字稿

Welcome to Range Resources' second-quarter 2007 financial results conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statement. After the speakers' remarks there will be a question-and-answer period.

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

Good afternoon and welcome. Range Resources reported results for the second quarter of 2007 was record production and our 18th consecutive quarter of sequential production growth, while reducing direct operating costs by over 10%.

There may be some confusion in our reported numbers due to the reclassification of our Gulf of Mexico properties as discontinued operations in the GAAP financial statements. In the press release we have furnished you some non-GAAP statements which allow you to compare our results to our historically reported numbers, which included the Gulf of Mexico operations.

On the Web site in our supplemental tables for the quarter, we have presented in table 5 a summary of the reported numbers which correspond to the analyst' models taking out the non-recurring and non-cash items. Table 5 shows concisely the amounts which compose our $0.41 of fully diluted earnings per share reported in the quarter.

On the call today with me are John Pinkerton, President and Chief Executive Officer; Jeff Ventura, Executive Vice President and Chief Operating Officer; and Roger Manny, Senior Vice President and Chief Financial Officer. Before turning the call over to John I would like to cover a few administrative items.

First we did file the 10-Q with the SEC this morning. It is now available on the homepage of our web site or you can access it using the SEC's EDGAR system. In addition we have posted on our web site supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the web site that will give you detailed information of our current hedge position by quarter.

Secondly, we will be participating in the Intercom Energy conference in August in Denver and the Lehman conference in early September in New York City. We hope to see you there.

Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the second-quarter financial results, I will review some of the key accomplishments so far in 2007.

One, on a year-over-year basis, second-quarter production rose 19%, being the high end of our guidance. As Rodney mentioned this marks the 18th consecutive quarter of sequential production growth. Achieving sequential production growth this quarter is particularly impressive, given the sale of our Gulf of Mexico properties closed on March 31st. As a result and in addition to overcoming the normal production decline we had to make up $14 million per day we lost with the Gulf of Mexico sale.

My hat goes off to our operating teams who do a magnificent job of keeping our streak alive. Without sounding too braggadocious, Ranger is the only E&P company with a market capitalization between $1 billion and $10 billion to have achieved 18 consecutive quarters of sequential production growth.

The primary reason we were able to achieve this growth was the success of our drilling program. For the quarter, we drilled 302 wells with only three dry holes. We continue to be extremely pleased with the drilling results and are generating very attractive rates of return. We currently have 37 rigs running and are on track to drill 971 wells for the year. The 19% increase in production and 18% increase in realized prices, coupled with lower-cost grow of 44% increase in cash flow year over year. Cash flow per share rose to over $1, reaching $1.04 for the quarter.

We are most pleased on the cost side as our operating costs fell 13% from first quarter this year. As a result, our cash operating margin for the quarter was $5.46 per Mcfe -- up a staggering 20% year over year.

Besides the operational progress, we completed five transactions in the first half of 2007 which results in a better more valuable range. We completed two property sales (inaudible) as $237 million. The assets we sold were high-cost mature properties with limited upside potential.

Conversely we completed two small acquisitions for $59 million and then a larger $279 million Nora transaction in mid-May. With all three of the acquisitions we bought interest in fields that we have already been very successful and had a lot of history and where we see substantial upside potential.

Fundamentally we traded a high declined production for a lower declined production resulting in the flattening of our overall decline curve. As a result the percentage of capital we need to spend to main our production base is now less, which allows us in turn to spend a greater percentage of our capital on projects that will fuel future growth.

Lastly, we ended the quarter with a stronger balance sheet which Roger will talk about. We also entered the quarter very well hedged. For the remainder of 2007, we have 80% of our natural gas production hedged at an average floor price of $8 per Mcf. So we are not too distracted by the recent dip in gas prices.

All in all, I couldn't be more pleased on how well and how -- with the performance and what we've accomplished in the first half of the year, it is a real testimony to the entire Range team.

With that I will turn the call over to Roger to review the financial results.

Thank you John. The second quarter of 2007 set another record for oil and gas sales of $220 million of production volumes that were 19% over last year. EBITDAX of $173 million and cash flow of $156 million for the quarter were the second highest quarterly results in our history. Realized prices rose 18% year over year partially helped by our strong hedge position.

As John mentioned, cash margins for Mcfe for the second quarter was $5.46 or 20% higher than the second quarter of 2006.

Bottom line reported earnings reflect a 25% increase in net income. As you recall and as John mentioned, we did close on the sale of our Gulf of Mexico properties on March 31st. So the second quarter of '07 represents the first full quarter without the Gulf of Mexico properties.

Under the accounting rules for discontinued operation, all financial results of the property sold are condensed into a single line item appearing below net income from continuing operations. And while the second quarter contained only a small true-up entry from the Gulf of Mexico sale, the year-to-date $63 million after-tax gain from the sale is significant.

To assist investors in truing up their historical numbers and projections -- which may include results from the properties we sold -- we have filed an 8-K which reclassified as five prior years of our results from operations before the sale. As Rodney mentioned to further assist investors, his team has posted several detailed discontinued operations schedules on the Range web site and included that information in the press release.

Looking at the second-quarter income statement for a minute, before we get to the balance sheet, direct operating expense was up on a unit cost basis from the prior year. However the big news here is that second-quarter direct operating expense of $0.86 per Mcfe was significantly below the first quarter of this year. This is the second consecutive quarter where direct operating expense for Mcfe was flat or down from the prior quarter, effectively holding the line on the operating cost increases that have been a factor for several years.

It is interesting to note that on an absolute dollar basis, second-quarter direct operating costs is lower than the first-quarter figure even though production volumes were higher. Production taxes for the second quarter were $0.39 per Mcfe, slightly lower than last year due to -- I'm sorry -- slightly higher than last year due to higher prices.

At the year-end conference call we anticipated that direct operating costs would begin the year on the high-end of the range with some relief occurring later in the year. And we are pleased to make good on that projection. Looking to the third quarter, we anticipate that direct operating costs will be in the $0.90 per Mcfe range.

Moving to corporate overhead costs, G&A expense per Mcfe for the second quarter adjusted for non-cash compensation expense was $0.44, up $0.07 from the second quarter of '06 and up $0.02 sequentially from the first quarter of this year. Half of the quarter-over-quarter increase is tied directly to the staffing of the new Range Pittsburgh office and the other half is associated with the continuing hiring of additional technical staff, including associated occupancy expense.

G&A expense is anticipated to remain in the mid to high $0.40 range going forward, as we continue to staff up for future growth and act to retain our staff of experienced and talented professionals.

With the 12% Range stock price increase from first quarter end to second quarter end non-cash deferred compensation plan expense totaled $9 million for the second quarter. The non-cash expense stems from the quarterly mark-to-market adjustments of securities held in the employee deferred compensation plan. Last year this expense for the second quarter was actually the $2 million credit. This non-cash deferred compensation plan expense is disregarded in the First Call analyst estimates along with other non-cash stock compensation included in the various expense categories. The press release again contains the detailed breakout of all of these non-cash amounts.

Interest expense per Mcfe in the second quarter took a bit of a breather as we reduced debt during the quarter with the proceeds of asset sales in our equity issuance. We then drew it back later in the quarter to fund acquisitions. So second-quarter 2007 -- so interest expense per Mcfe of $0.62 up $0.12 from last year, down $0.10 from the first quarter of this year.

Going forward in 2007 our interest expense for Mcfe assuming stable interest rates and capital spending should be in the high $0.60 range.

Exploration expense adjusted for non-cash compensation was $11 million in the second quarter of 2007. That's flat the first quarter of this year. Based on our drilling plans for the rest of '07 we expect exploration expense to be in the $10 million to $12 million range for the third and fourth quarters.

The DD&A rate for the second quarter was $1.81 per Mcfe compared to $1.80 per Mcfe in the first quarter of this year. It was a $0.04 per Mcfe reduction in the first quarter DD&A rates as a result of the Gulf of Mexico's sales. The DD&A rate for the remainder of '07 should be in the $1.80 to $1.85 per Mcfe range.

The income tax rate for the quarter reflects a one-time reduction in the effective rate to 34.5% due to a state tax credit. Going forward in future quarters we will return to our 37% effective rate.

More good news on the tax front may be found in the second quarter of '07 from the continued successful redeployment of our Austin Chalk asset sale proceeds that are being held in a 1031 like kind exchange account. At the end of the second quarter the 1031 account balance was $16 million and this has subsequently been reduced this month to $4 million through the acquisition of additional Barnett Shale acreage that was mentioned in our recent operations press release.

The tax gain from the sale of the Gulf of Mexico assets will be absorbed by intangible drilling costs deduction from our '07 drilling program such that little, if any, utilization of our $230 million NOL Federal carryforward is expected to be required.

As I mentioned earlier in my remarks, EBITDAX for the second quarter was $173 million and cash flow for the second quarter was $156 million. Cash flow per share for the second quarter was $1.04, up 30% from the second quarter of '06. Cash flow per share is $0.03 higher than the First Call of consensus estimate of $1.01. Net income per diluted share for the second quarter calculated in a manner similar to the analysts is $0.41 and that is up $0.37 from last year and $0.03 over the First Call consensus estimate of $0.38.

Six-month year-to-date EBITDAX was $354 million, up 36% compared to the $260 million figure for the first six months of 2006. Cash flow for the first half of this year was $318 million, 34% higher than the $237 million figure from the first half of last year. The first half of 2007 saw production 19% higher than last year on oil and gas prices that were 13% higher.

All reconciliations of all of these non-GAAP financial measures to GAAP are available on the Range Resources website and the press release.

During the second quarter Range established a floor price for the majority of its 2009 oil production of $64.01 per barrel and we retained significant upside with these hedges by using collars. With the recent natural gas price declines, our gas hedge position appears even more attractive than before. We currently have an estimated 81% of our remaining '07 gas production hedged at a weighted average floor price of $8.00 in MMBtu, and an estimated 58% of our '08 gas production hedged at a weighted average floor price of $8.91 per MMBtu.

The positive impact of our hedges has been visible in both our first- and second-quarter '07 results. As Rodney mentioned anyone wishing to update their financial models or review Range's hedging position in greater detail can find summaries of our hedged positions on the homepage of Range's Website.

The second quarter saw continued improvement in the Range balance sheet as debt was reduced with the proceeds of $155 million Gulf of Mexico sale and the stock offering that netted proceeds of $280 million. The debt was subsequently partially redrawn to pay for the $279 million Nora Field transaction.

Now the Nora Field transaction did include the purchase of a 50% equity interest in the Nora gas gathering system. And this purchase accounts for the majority of the quarterly increase in the equity method investments line of the balance sheet. When all the dust settled, we ended the quarter with slightly less debt than we had at year-end '06 and considerably less debt than we had at the end of the first quarter and a sharply lower debt to cap ratio of 39%.

Our listeners are to be commended for their patience and listening to me talk for almost two years about our target 40% debt to cap ratio. It's a good feeling to finally achieved the target. Standard & Poor's acknowledged our improved credit quality by upgrading our senior subordinated notes during the quarter to a single B+ and our corporate rating to a BB flat.

In summary the second quarter of '07 was an exceptional quarter producing record oil and gas revenue, second best ever quarterly EBITDAX cash flow and earnings, combined with achieving our target debt to cap ratio and a rating agency upgrade. Cash margins continued to improve significantly from '06 levels thanks in part to our strong hedge positions and declining direct operating expense. So we remain on track for another record year for Range.

John, I will now turn the call back to you.

Thanks, Roger. Great job. I will now turn the call of her to Jeff to review our exploration development activities.

Thanks, John. I will begin by reviewing production. For the second quarter, production averaged $313 million per day, a 19% increase over the second quarter of 2006. This represents the highest quarter production rate in the Company's history in the 18th consecutive quarter of sequential production growth.

This is particularly impressive given the sale of our Gulf of Mexico properties, which were producing 15 million per day when the sale closed at the end of the first quarter. We didn't close on the acquisition of our additional interest in Nora Field until mid-May. We only closed on 83% of the production. Despite that and on top of the fact that we had a normally wet weather in the MidContinent area in the Fort Worth Basin our team again met the challenge and delivered our 18th consecutive quarter of production growth.

We accelerated a number of projects to the second quarter to assure ourselves we were making guidance for the quarter. We will move to more flat spending of capital for the third and fourth quarters, but still expect to deliver 16% production growth for 2007.

I will now review three of our key projects. I will start with the Barnett Shale in the Fort Worth Basin. We have increased our acreage position to approximately 86,000 net acres. This time last year we had about 36,000 net acres so our position has more than doubled. Production continues to grow and today we are producing about 60 million per day net. At the time of the Stroud acquisition we were producing about 16 million per day from the Barnett. So our team has almost quadrupled production in little more than a year. This is outstanding performance from our Barnett team.

Our first Ellis County well has been drilled and cased and will be fracked shortly. This project is an attempt to push the eastern extent of the Barnett trend from Johnson County across the county line into western Ellis County in northeastern Hill County where Range has a lot of acreage.

Current eastern edge of the plate here is represented by Range's (inaudible) well on our East Venus acreage which is on the far eastern edge of Johnson County, and by multiple EOG wells in northeastern Hill County. The extension area that we are drilling is in an area that is based on our 3-D which looks quiet and that means that it is not (inaudible) and has relatively wide space faults.

Range is not the only company drilling in Ellis County. Directly to the North Harding, in partnership with Exxon and Petro Search, and EOG independently, are also in drilling and completing wells.

Overall our team has done a great job in the Barnett. Both our acreage and production will continue to grow. Importantly almost all of our acreage is in the core or expanding core part of the field. We believe our acreage has more than 2 tcf of potential net to Range. Our acreage coupled with our talented experienced team will continue to build value for our shareholders.

Another very impactful low-risk project for us is our Nora area located in Virginia in the Appalachian Basin. Net production has grown from approximately 14 million per day at the time we acquired these properties in December of 2004 to about 29 million per day prior to our recent transaction with Equitable. Including the acquisition our production in this area now is about 45 million per day.

There are three key horizons that will be developing at Nora. The first is a Pennsylvania (inaudible) coals.

There are currently more than 1100 existing coalbed methane wells on our property. The average well cost about $350,000 to drill and complete and the average (inaudible) reserves to date are about 440 million cubic feet per well.

Given our 50% working interest and 56% net revenue interest in most of the acreage, our [finding] and development costs for these wells is below $1. Most importantly there is 2.4 tcf of gas in place in this prolific CBM field. If we can achieve a 70 to 80% recovery of the gas in place grows reserves will be in .7 to 1.9 tcf. Net the range we would have left to recover .8 to 1 pcf. Only 200 bcf of the gas is currently booked which gives us great low-risk upside. This upside will be achieved through continued development and infield drilling and recompletions.

The second key horizon is the type gas sands below the coalbed methane horizons. These Mississippi and eight zones exist from 4000 to 5000 feet deep and historically have reserves of about 575 million cubic feet per well. The cost to drill and complete is about $500,000 which again results in great finding and development costs. They have been historically drilled on 112 acres spacing.

This year we will test down spacing in this horizon. Based on the current spacing it appears that we are recovering less than 50% of the gas in place. Theoretically, with continued drilling, down spacing and additional stimulation, we should be able to recover 75 to 80% of the gas in place. Net the range this could add over 100 bcf of infill drilling successful.

The third key horizon is the Devonian shale which is from 5000 to 6000 feet. Nora is about ten miles east of Big Sandy field which is directly to the west in Kentucky and has produced more than 2.5 tcf from the Devonian shale. The Devonian shale exists across our entire 300,000 acre position here and historically was completed and commingled with the type gas sands in over 90 of the existing vertical wells.

One of the vertical wells has produced 1.4 bcf with a small [foam] frac and is anticipated to produce 2.2 bcf ultimately. We will be drilling horizontal wells and completing with multiple stage foam fracs to try this new technology here. If successful it could add over when tcf net to range. We should have our first horizontal well in Nora drilled and completed late this year.

Another high impact opportunity for Range is our Devonian shale plane in the northern part of the Appalachian Basin. Although this project has higher risk it represents another opportunity to more than double the Company by itself. The Devonian shale represents 2.5 to 5 tcf of upside potential and, currently, we have more than 470,000 acres net acres in the play.

Our three oldest wells have been online for about a year and a half. Results for these wells still indicate an estimated reserve potential of between .6 to 1 bcf per vertical well.

In the early phase of horizontal drilling we drilled three horizontal wells. We have now completed those wells and reserves for two of the wells are about 1.5 bcf each. The third well wasn't successfully completed and will be converted to a vertical well.

Going forward we are looking at increasing the number of horizontal wells to be drilled this year and decreasing the number of vertical wells. We have moved in two rigs and are drilling the second and third horizontal wells of this new phase of drilling as I speak. We expect to begin completing the new horizontals in August.

We are doing this for two reasons. Based on analogy to other shale place in the country, horizontal wells are more economic than vertical wells. Also theoretically a low permeability rock will produce higher rates with more surface areas of the formation exposed to the well bore which will be the case with a horizontal well. We have a good feel at this point for vertical wells in the area that were drilled and going forward we will get a good feel for the horizontal wells.

In addition to drilling more horizontal wells we will test more of our perspective areas by the end of this year, including wells in multiple areas in Pennsylvania as well as Virginia and West Virginia.

Finally, we will start drilling our low-cost vertical -- or we've actually started drilling our low-cost vertical pilot program in southwestern Pennsylvania in order to confirm that we can drill and complete vertical wells for approximately $900,000 and, therefore, generate really attractive finding and development costs. We have many other high-quality exciting projects which I'll be glad to talk about during the Q&A.

But to summarize, Range is in a great position. We have a proved reserve base of 1.9 tcf. On top of that we've identified upside of between 8 to 11 pcf primarily in low-risk coalbed methane, shale gas, and tight gas sand place. We have a great track record of converting that to value for our shareholders. Range is where we want it to be -- a low-cost producer with a lot of low-risk built-in growth with great hedges in place.

In summary we are in a terrific position to continue to build shareholder value on into the future. Back to you, John.

Thanks, Jeff. Terrific update.

Looking to the remainder of 2007, we continue to see strong operating and financial results. We are looking for third-quarter production to come in at approximately $322 million to $324 million a day. That will be another record. Hopefully our 19th consecutive quarter of sequential growth.

Turning to prices, assuming current futures, prices, and hedges in place as of yesterday we anticipate third-quarter price realizations after hedging to be in the $7.35 per Mcfe range. This is $0.86 higher than the $6.49 realized in the third quarter of 2006 but slightly lower than the second quarter 2007 due to the recent dip in natural gas prices.

However we again anticipate third-quarter revenues, cash flows and earnings will be substantially higher then the prior year period.

Looking beyond the third quarter we anticipate production to continue to increase in the fourth quarter, as a result of the success of our drilling program. Based on the solid results of the first half of the year, we are well on our way to achieving solid double-digit production growth for yet another year. We feel very comfortable with our 16% production target.

Due to higher volume and prices and stable costs, cash flows from operations for 2007 is anticipated to increase by an amazing 40% over 2006. For the year, we anticipate record revenues, cash flow and earnings while ending the year with a stronger balance sheet.

So as you can see 2007 shapes up to be a tremendous year for Range and its stockholders.

While focused on getting our wells drilled and hitting our quarterly production targets, we also continued to expand our drilling inventory to make solid progress with our emerging plays. As you've heard from Jeff our technical teams are making exciting progress. Today, we have the largest drilling inventory in our history with over 10,000 projects. Our inventory including our emerging plays now represents 8 to 11 tcf or future growth potential for Range.

As Jeff mentioned, we really believe we are in a unique position that for our size we have a very large transparent drilling inventory, and an even larger over three-man growth (inaudible) position.

When you really look at what we do on a day to day basis, we really do two things. We work tenaciously to maintain our top quartile cost structure. At the same time we are focused on expanding our drilling inventory to drive long-term growth and profitability.

Lastly, just taking a snapshot of the next 12 months, it is going to be a very exciting time for us at Range. Due to the large drilling inventory, the low-cost structure, and the hedges in place we are quite confident that we will deliver record financial results that will be on the superior side for our peer group. As a result, we can focus all of our time and effort on projects that will drive our valuation.

This includes some of the project Jeff talked about including the eastern extension of the Barnett, the tremendous CBM tight gas and shale potential at Nora, the Devonian shale plants in Appalachia as well as a number of other exciting projects that our teams are working on.

For many of these projects, the exciting part is that we should see meaningful clarity within the next several quarters. I'm confident that one or more will be successful at which time when turn drive our evaluation up much better than what it is today.

With that, operator, why don't we go ahead and turn the call over to questions? And we will see if we can answer them (inaudible).

(OPERATOR INSTRUCTIONS). [Tom Gardner] with Simmons & Co.

Concerning Nora Field 30-acre down spacing, what information can you offer that might give us a view of the ultimate success or failure of down spacing?

I can say at this point in time we feel really good about the down spacing. We drilled a total of 16 down space wells in '06. This year we are going to drill several more. We have probably got 12 of them drilled and online and it's very encouraging. The results of the down space wells look very similar to the original 60-acre wells although it's very early and obviously you want more history. But so far it looks great. We are very encouraged by it.

The other thing to remember too is that down spacing is exciting and I think again through down spacing and through just continued development on 60 acres plus down spacing to 30s and recompletions we may have somewhere close to a tcf net to range to recover out of the CBM but there's 2760-acre wells left to be drilled. So we have got a large drilling inventory ahead of us.

Now that we are in line with Equitable we are significantly ramping up the pace of drilling and we will be adding a lot of net present value out there.

And do you see 30-acre down spacing as successful applicable over the entire area?

Yes. That's something that you move with time. Yes, I think through a combination I feel good about you have got a really high-quality coalbed methane field that is really well-defined. You've got a tremendous amount of gas in place and then is just a matter of optimally developing it to achieve those higher recovery factors. But yes I think potentially that you could basically infill the whole thing.

Thanks Jeff. And on a different note here given your asset base, it would appear that some of your properties might be suitable for an MLP. Have you review this and can you speak to the pros and cons?

We have -- I was just eating a potato chip. You'll have to pardon me. Yes, in 2005 we spent an entire year quite frankly reviewing the MLP structure and the pluses and minuses of it. One of my learning experiences in life is, in 1982, I was involved with managing one of the first E&P MLPs ever created. So I kind of had MLP 101 first hand.

But through that experience and the work that we did in 2005, we concluded at that time that we should stay kind of C corp, stay simple and not pursue it. Obviously given what is going on in the market it seems like every investment banker on the planet Earth is pitching it.

But from our perspective a couple of things. One, over the long-term we don't think the structure is going to dictate how investors [evalue] on gas reserves. So we think it's a short-term phenomenon that if MLP prices stay up it will be a big boost -- lift to Range as well as some of the other C corps that have really long lived production.

The other thing is that we're really focused on trying to keep Range simple and trying to have a structure that has no conflicts and where we know we said to shareholders we work on every day. And so I think from that perspective it tilts us from not doing one.

In terms of having an acquisition vehicle amount. The kind of acquisitions we do really don't fit MLPs to begin with because they are largely nonproducing, largely unproven and usually take quite a bit of capital and really good technical team to make it work. So that's another reason not to do one and our -- to the extent that we want to quote gain or take advantage of quote "arbitrage" that's happening which I think will go away with time, quite frankly, quite quickly. We can always sell assets to those that do created MLPs.

So from all that that is kind of our conclusion right now so I think we are 80 to 90% convinced at least in this point in time we should just stay simple, stay focused. We got a big inventory of projects. Just keep belting out the quarter-over-quarter production growth at a low cost and I think the market will continue to reward that and also I think the market will reward us for having a lot of transparency and a lot of simplicity as well.

If I could just sneak one last question in on the Pennsylvania Devonian. I will try to make it direct. Just that 1.5 bcf that, Jeff, I believe you indicated two of those three results were likely to produce ultimately. If you can get the cost where you think they should go with that we can step up economically to the verticals?

I would just say at this point -- one, let me back up. When you again if you put the verticals in perspective, if we can drill and I believe we can for $900,000 or less. But say it's $900,000 and you take the midpoint of the reserve range. .6 to 1 is $800 million. So if we can spend $900,000 on a vertical to get 800 cubic feet -- 800 million cubic feet of gas and remembering our average working interest is about 100. Our average NRI is about 86. Where we are at now is about 1200 BTU gas. So $5 NYMEX. Currently we are getting paid for the BTUs ultimately to process them.

So $5 NYMEX with 20% BTU uplift at $6 plus in the Appalachian Basin you are getting a premium of $0.35 where we are So $5 NYMEX is $6.35 to us. So $900,000 for $800 million with our interest is $1.30 to $1.40 finding cost.

So that is pretty exciting. That's why this low-cost pilot is really interesting. We think we can do it on paper. I believe we can do it in the field. But we are going to go out there and try to verify that so that looks pretty exciting.

Then the other thing though the question becomes is, will horizontal wells be more optimum. We drilled three wells early on. Instead of drilling a number of vertical wells like people had in other plays, where literally in a lot of plays they drilled 50 to 100 or more vertical wells before they drill horizontally. We put three wells in out of our first 13 wells. Three of them were horizontals and like most of these shale plays, there's a learning curve.

So actually in hindsight we didn't do bad. Being a half per horizontal well is pretty good but we think we've learned a lot. So now is a matter of what looks more attractive economically. Would it be horizontal or vertical? The good news is we've got some wells that are already drilled and cased and we will be fracking them and completing them here literally within a couple of weeks to start this next phase. And we think how you drilled the wells and how you place them and how you frac them will make a lot of different.

That's what we are what to be looking at so by the end of the year we will be in a lot better position to look back and say a few things. One what's the vertical wells look like and can we do it in the field like we think we can do. What do horizontal economics look like and then as we test more areas how does some of these other areas compare with what done so far?

That was a long answer but that's been the reality of what we're doing.

Marshall Carver with Pickering Energy Partners.

One, what went wrong with the third well in the Devonian shale? Did you say specifically what happened there? And can -- do you know if you can fix it?

Excellent question. These are answers -- yes we can fix it by turning it into the vertical well. That to specifically answer it, one thing that's really important to look at is we've got 470,000 acres and in reality a lot of our other acreage may be perspective for the shale. We got 2 million acres in the basin. So we got a tremendous position.

Clearly when you look at the shale play in the northern part of the Basin we're the industry leader in terms of drilling and producing and experimenting. And that is a position we like and we want to be in. I can tell you what the answer is. I don't want to and I -- but right now we are not going to tell you what the answer is because we think there's a competitive advantage to what we are learning in terms of how to drill the wells, how to complete them, how to place them, how to orient them and we want to keep that advantage to ourselves as long as we can.

At some point in time we will come out like we have on every one of our other projects and get into those kind of details but right now we are going to keep that confidential.

Okay.

Just, Marshall, it's John -- just add on to that. I think it's you know as Jeff likes to say a lot of the stuff that we are doing now is kind of like going to the doughnut shop. One day you pick a sprinkled doughnut, next day you pick a chocolate covered doughnut. And so we are trying all of these different ways of doing things with the idea of trying to unlock the key here. We understand that some of them are going to fail.

And that was one of the ideas we had to do it a certain way and it failed. So hopefully elite we learn from our lesson and we -- but again you had go through a series of steps like that. Especially when you are kind of out in front of the pack and you're going to have some failures along the way.

But again the key is that we gone through a lot of that. We obviously wouldn't have moved up two rigs from Texas. Two horizontal rigs up to Appalachia if we didn't feel confident that we could unlock at least two some prospective some of the keys here. We are still going to -- we are still way down on the learning curve but we feel like we've learned a lot and you can see it with each well that we drill and the things that we're doing. It's quite exciting.

But again just like everything else, it took 13 years from for the Barnett to go from where it was in infancy to where to where it was relatively commercial. And we are trying to do the same in the Devonian in about three years. The good news is that looks like we are right on pace. So pretty happy, pretty pleased and like Jeff says we will have -- we're going to have a quantum leap in terms of data and a confidence factor by the into the year. That's pretty exciting. That's not too far away.

Thank you. One other quick question. What is your quarterly CapEx run rate with the 37 rigs running now?

I can tell you this. I mean just like I mentioned in mine, we had talked about with additional acreage our spending this year would be about $835 million excluding acquisitions. And we are right on track by the end of the year to get our 16% growth with that capital spending.

Just to add a little color to what Jeff said is that one of the ways that we were able to overcome the loss of the Gulf of Mexico properties is our guys really worked. Once we got a pretty good idea that we were going to sell the assets and Jeff went out to our teams and really through the gauntlet down in terms of a challenge. And those guys really one out and sped up quite a bit of work and moved some wells that they were going to drill later in the year to earlier in the year. A lot of recompletions. They really did just an unbelievable job of moving capital around and really hitting the ball out of the park.

That being said, the good news is we did that without having -- usually when you do that your cost structure tends to have a dent in it. The good news is it actually we didn't suffer any lack of costs. We actually did a little bit better on it in terms of LOEs, and I think we did pretty good in terms of capital deficiency.

But with all that being said is quite frankly we will spend less capital in the second half of 2007 than we did in the first half of 2007. So to give you a feel. So again, we sped up a little bit and now we are going to -- we are not going to slow to a walk but let our guys kind of take a breather. Little bit of a breather, let them kind of their breath and because you know we got good growth. We feel like we are going to have really good reserve or placement finding costs [this year].

So no reason to take any risk with that.

Ron Mills. Johnson Rice.

It's actually Clay Cummings. Jeff, just a quick question follow-up on the Devonian shale and the Pennsylvania. You spoke in detail about the economics of the vertical wells. What is -- what are you guys looking for from these horizontal wells to get a like return in terms of reserves and production out of those wells?

To answer -- to attempt to answer your question, the reason why I spoke in detail about the vertical wells is because we've drilled a number of them and again our oldest wells have been online now for a little over a year in a half. So we have pretty good production history. We've got good reservoir modeling. I feel comfortable with the reserves and drainage and costs and all those kind of things.

But we are early into the horizontal part of that. So once we get like I say probably by end of this year, early next year, we will come out with some -- a lot more specific guidelines in terms of horizontals. I really don't want to get into that yet until we get more history and more of that under our belts.

But I think -- I'm encouraged that we've learned a lot. I'm encouraged that horizontal I think is a good solution. If all we ended up with was a vertical play just like I describe that's pretty exciting. I drill wells all day at $1.30 and Mcf and for add a $5 NYMEX, a high 20s rate every turn. So that's exciting in and amongst itself.

We've got a lot of acreage, a great team. That's where the roots of the Company are. But for horizontals, theoretically horizontals could even be better but now we need to go out there and see it in reality we can achieve that. And once we get more under our belt and we get more history then we will go through the same amount of detail and tell you exactly what it costs to drill them and what we think the reserves are.

But we will also as long as we can to the extent we feel we have a competitive advantage, we are going to keep some of that stuff tight to the vest as we continue to acquire acreage and build our position.

Fair enough. Just a quick question again on the Devonian and the Nora Field. You had mentioned you were attempting to try this multiple foam frac in the horizontal well there. Is that something that you are going to perform in the Pennsylvania Devonian as well? Or can you just give me a little more detail on what you are looking for from that versus I guess conventional horizontal frac?

Yes well in the southern part of the the Basin, you know our partner in Nora is equitable. We are 50-50 and in line with Equitable. Both sides are excited about the potential of the shale in Nora. Equitable already has had good success in Kentucky drilling in Big Sandy, which is like I say the stuff we are drilling is just an extension of Big Sandy. It's a little bit deeper, but it's going to be very similar.

So we are going to use the same technique that Dev used and also (inaudible) used successfully a little bit farther up north up in the West Virginia. So remembering in that southern part of the Basin is that subnormally pressured it's the (inaudible) shale member. So Dev sort of both of those companies are particularly equitable since they are a lot closer to where we are -- have proven that when you drill a horizontal well with multiple -- you know basically Packers plus or an open hole Packers style completion with multiple foam fracs you can get good results. So that's what we're going to try at Nora.

The good news at Nora is you've got 90 wells there that show the shale goes across that entire acreage position and is charged with gas and is good thickness. So we feel good about that.

What we're doing in the northern part of the Basin to contrast that a little bit though is it's a different play because as you go north it gets a little bit deeper. But it also, in the southern part, you have a naturally fractured shale play and that's why Big Sandy began production back in the 1920s so that field has been producing forever. Because it's with natural fractioning and 1920s, '30s, '40s and '50s technology you could produce gas from it in commercial rates.

In the northern part of the Basin where you don't have that natural fraction you do not have the natural fracturing but you have some other advantages to it and that it's a little bit deeper. It so that higher pressure because it's deeper but also has a significantly higher pressure gradient. You have about a .5 PSI per foot gradient roughly at about 6000 feet. So you got 3000 lbs reservoir pressure. To the south even initially Big Sandy was very subnormally pressured. You know .15 to .2 gradient (inaudible) it 4000 feet.

So you've got 800 lb reservoir versus 3000. The good news is more pressure more gas in place. So you got a tremendous amount of gas in place up in the northern part of the Basin. There's different studies that have been out there for a long time. USGS says there's well over 200 tcf of gas in place.

So it's a giant number and the question is can you recover enough of the and at an economic rate to make it commercial.

But in the northern part you are probably going to use looking at more of the slick water fracs where you get better extension and you get more surface there. And you can do that in the north because you got more reservoir pressure to get that fluid back off it. In the South you can't do that because of the low-pressure so you have to use foam fracking.

So it is sort of a long answer to your question and we could talk about it for hours, but hopefully that gives you a little color to what we (inaudible).

That's great. Thank you. Then last question. In the Barnett Shale of the 22,000 acres that you've added in the play. Can you comment on where that is? Is there any blocks associated with it or is there any -- actually could you also give an update as to the acreage position in those counties as well?

Yes. None of the new acreage was in Ellis County. So the acreage was all in and amongst where we recurrently are. It's in eastern Hood, eastern Parker, northern Hill, some in Johnson. So it is in and amongst where we are currently. None of it added to our Ellis County position.

So I am excited about the acreage. We think it is very perspective. Obviously it adds a lot to our reserves and we meet people periodically. And if you notice as we add acreage to a lot of the plays rather than updating our 8 to -- we have 8 to 11 tcf of upside, if you look on our little tables that are out on our web site or at some of our presentations when we add acreage, we just add a little + to the end. So it's instead of continually -- on the Barnett we are saying there's 2 tcf of potential but we were saying that when we had a lot smaller position.

Obviously our -- we think the acreage is very perspective when we update our reserves that number would be significantly higher. But we just do that periodically like once or twice a year. So I'm excited about the acreage. It's not the eastern extension play that we added to. I'm still excited about the eastern extension.

We will be fracking that well literally in a couple of weeks. We drilled it. We found a nice section of Barnett with gas, just like we expected. And now we will be fracking it to see how that performs as well.

David [Cameron] with Wachovia.

John or whomever, can you guys comment a little bit on what you are doing on Permian? Is it New Mexico, West Texas area, what your activities look like out there?

I will talk a little bit and let Jeff kind of fill in some of the details. But we are continuing to develop out our New Mexico properties are doing well. We've got some rigs running there and we drilled some good wells and production continues to climb at [Fuhrman]. We had some real good success at the beginning of the year. The five acres spacing wells look terrific and we got beaucoups of those which is a technical term. Five acre locations left and so we are real pleased with that. Obviously that's a oil play so with these kind of oil prices, it's extremely attractive.

We are still continuing to -- we -- amazingly enough down in the Sonora [Congra] field we -- just this year I think we drilled the best well we've ever drilled in a field that was supposed to have been relatively mature. So we are excited about that.

There's some other things that we are doing in terms of some other formations in that area that, if they work, could be pretty significant in terms of upside. We've done a few of them. We are doing some signs on those so those are -- for relatively mature assets it's been quite comforting with the progress we've made and continued.

It gets back to what Jeff says. We got this really great team of people that are focused on each of the assets they're working on it and it's really is been fabulous busy in areas like Sonora and Fuhrman and New Mexico which are considered relatively mature areas, to see how well they've done and increase production and reserves in these fields.

That is really when it comes right down to it, that is really what has driven Range's 18 consecutive quarters of sequential production growth -- is that the underlined assets that drive the Company are performing better than our 'PDP' or our proved reserve report of 1.9 tcf. It is doing better than that.

So that is really what's driving the upside in terms of the production, and some of the other things quarter to quarter, is that asset base. But the reason what drives that is we've just got an extraordinary group of people that we put together here that are really driven and own a bunch of the stock and wants the stock price to go up.

So it is all part and parcel of the culture we built and kind of assets we own. That being said we continue -- Chad and his team are looking at some assets to the divest of and we've got probably three pods of assets that we're considering or evaluating right now. Similar in nature in that they're relatively mature in one case on a relative basis as higher operating costs that some of the other assets. So we are going to continue as we move along -- continue to divest of things -- and as one of the callers said before, you know there's been no better market to divest of assets than this market right now, given the appetite of some of our cash flow hungry MLP friends.

So it's -- from our perspective, we sit back. You know it's just -- it's amazing how at least from our perspective how well-positioned we believe the Company is and I don't think it's by luck. I think it's by -- we've worked really hard. We put a great team together. We kept it simple and we're not trying to be the biggest or fanciest company but we are just trying to be very consistent, very disciplined and continue to work on our big projects? And as Jeff said if one of them works we are going to double the Company.

Stay right there with the Permian. What's your -- if I take out the Barnett out of that division? I think you lumped the Barnett in there. What's your growth rate look like or what's the underlying production look like?

If you -- before we even got into the Barnett the Company was growing at a good percentage for the year. And if you look at the best growth in the Company really was coming out of the Permian before we were ever in the Barnett. And, simplistically, if you look at a lot of the areas we are in or almost all the areas we are in, we get into areas that have a lot of hydrocarbon in place. And then we have really good tackle things that just figure out how to get more.

So and -- I use -- in the Permian I'll use a couple of these examples. In Fuhrman before we started working on the properties they were producing about 300 barrels of oil per day; and through a combination of redevelopment, infill drilling and some refracting we drilled production up to 3000 barrels per day in a pretty short period of time. So tenfold increase in production.

Where we were at that point in time we believe we are only recovering 10% of the oil in place. So by looking at five acres infilling and looking at water flooding -- both of which look very encouraging -- we think maybe we can double recovery to maybe 20% during the long run. Maybe approach 30%. So there's a lot of additional growth that we can get out of that.

Second example is in New Mexico and Eunice. We picked the properties up 7 million a day and into short period quadrupled production and not only quadrupled production but kept -- we were doing that for basically $1 in Mcf and about $0.70 [lip] cost. So we're getting really good growth out of our basic assets in the Permian and [Conger's] another example

But for time let me switch over and say not only is it getting into areas where you have a lot of hydrocarbon in place and improving recovery and driving rates up but we try to keep our eye on the ball and costs. If you come back to Fuhrman four years ago in Fuhrman it took us about 7 1/2 days to drill a well. If you go back about a year ago we had it down to maybe 5 1/2, 6 days and with new bit technology. I wouldn't say new bit technology but applying state-of-the-art PDC bits in different parts of the whole have actually driven the days on a well down to 3 1/2. half.

So that's a big difference in cost savings. So the guys are not only increasing reserves but if you look at the Company, you know our goal is simple, to drive up production year after year, quarter after quarter and have our cost in the top quartile are better. For the last three years in a row according to Bank of America study (inaudible) is looking at all in unit cost of F&D, LOE, interest expense and G&A. We are actually number 1 three years in a row. So when you are driving up production and keeping your costs down you are going to add a lot of value to your shareholders.

And so Permian is a great area. And again I could go on for two or three hours talking about new ideas, and new things that we have that we're going to try to extract a lot more continue to chip away at that recovery factor in these old fields that have a lot of hydrocarbon in place.

Just one more quick question. The Floyd shale. Where do you guys stand right now on the Floyd?

In the Floyd you know we are in five Shale place. Basically two of them and the Devonian shale and the Barnett shale in the Fort Worth Basin. We believe, through our position -- both our acreage position and the quality of our technical team we on on the leading edge of those plays and we want to be leaders. And the other three plays we are in we are more followers. That is the play we have been a follower in.

We get in and got very inexpensive acreage with literally 10-year, five-year leases with five-year tickers. So we were tying up a lot of acreage for 10 years basically. So we intentionally wanted to go a little bit slow and see what others in the industry have done.

Just jumping to the industry, it's interesting in that this year you actually have some shale players who have good experience with EOG, [Coreso], Chesapeake ultimately started drilling in there. And they are starting to do things in and around those areas. We just spud not too long ago our first well in the Floyd shale and our plans are to drill one vertical well this year, gather a lot of data, study it and then early next year follow up with a horizontal well.

But you have spud a well this year?

Yes.

And results on that, when would you like to share those with us?

Probably after we've finished our horizontal well. So it will be a ways out because, again, the Floyd sale is a lot more complex than probably a lot of the other plays. You can find the Floyd shale at 3500 feet or you can find it at 15,000 feet so you can find it any gas window and the oil window and its thickness varies and it's complex geologically. So where you are in the Floyd I think is going to make a big difference.

It's -- none of these plays, it's not all created equal even if you are in the Barnett. Obviously Tarrant County is a lot better than some county way out West or way to the south in Hamilton or something. The Floyd is going to be similar to that but probably even more so. Where you are is going to be important.

So I think we want to drill our vertical well which we are doing. Gather a lot of data. Study it, see what we will learn from that, see what we learn from other people and then follow up with horizontal. Probably after we are done with horizontal. So you're -- it's a ways out before we will be talking about it.

Ray Deacon with BMO Capital Market.

I was just curious what acreage costs were doing in the Devonian shale play in Appalachia and also you mentioned when you did the North transaction you may drill horizontal well targeting the shales there. Is that likely to happen this year?

Yes we will drill, on the Nora Field we will drill a complete horizontal well there. Really towards right at the end of the year and that will be using the same technology that Equitable is successfully using right across the state line in Kentucky. So we will do that and we are excited about that as is Equitable and then your other question was on acreage cost.

Now one thing about the Appalachian Basin it's -- John likes to point out it's the largest onshore basin in the U.S. So it's a big sandbox. It's a big area. And we are still acquiring acreage for attractive costs. In some parts of the basin and in some areas that's gone up some with competition but it's still, we think, reasonably priced. So we're still picking up acreage for attractive cost breaker and attractive royalties in areas we think are prospective.

Again we've done a lot of studying, a lot of work to -- not all areas are going to the design. Not all areas are going to be equal, but we are focusing and targeting areas we think have good shale thickness and are in the gas window at reasonable depths and all the other things that you look for; and I won't go on and on about what they are, but --

Right.

So far so good. We are going to continue to pick up acreage there.

No big escalation in cost, it sounds like. So it just -- .

Right. This is John. I do think in some of the areas we are picking up acreage for $25 to $200 an acre to give you a perspective. And there are a few areas that have gotten "went from $50 to $100 or $70 bucks to $160 bucks" or something. And part of that is just driven by the competition and the good news and the bad news is that some of the other shale players have bought and acquired some relatively large positions in the basin. Our friend at Chief, Trevor Rees Jones, just bought a big position in the Basin we heard of. We are relatively certain of that. And there's another pretty predominant shale player that's bought we believe a pretty good position in the Basin.

We actually you know -- that's bad news. The good news though it's -- you know, in both of those cases some guys have made a ton of money in the shale plays. Really smart bright guys that the next -- their next entrance in terms of play has been in Appalachia. So we found that really encouraging. That will help bring additional services, additional frac, solicit pumping equipment into the Basin. It will bring more in terms of top-notch services to the Basin.

So, overall, we think that's a positive. The good news is the Basin is one -- as Jeff said, it's one big Basin. So you have got to be a little careful. You could end the play if you don't watch out, being acreage rich and cash flow poor.

So again we have got our buy areas. We are going to continue to buy in those areas. We got 60 plus lease brokers, continue to work six days a week picking up acreage. We've got a leading industry advantage, we think, but at the end of the day it's going to come down to how much gas we can get out of the ground. And what's the performance of those wells going to be? And you know it's still early. It's still early yet.

Right, well, you've got a huge inventory. So that I guess one other question, John, is what you -- you've had I guess it's maybe 15% fall in the gas strip in the last quarter and oils gone the other way. Any thoughts to switching capital around as far as where you allocate your drilling in the second half or do you look at that until October, November?

That's exactly the reason why we hedge. You know we tended to be more hedged than our brethren. We really don't look at short-term gas prices. It really doesn't really have that big an impact on our business in the fact that we are 80% hedged at $8 or better. And we've still got some upside because most of those are collared.

So it really doesn't have a big impact in terms of how we look at the business. The good news is is that you are going to see service costs come down because of these prices. That's just macroeconomics so the good news is as we ramp up in some of these areas we -- will get -- we're seeing that in the Barnett in a big way, in the Barnett and some of the other more competitive areas. We are seeing some real big cost savings going on and I think it's related to people getting a little nervous over gas prices and what not.

But you know, again, as Jeff said most of the projects we are in we've been in a long time. We're a low-cost guy. We are well hedged. Most of our projects make exceptional rates of returns at $5 NYMEX unhedged.

So again the reason in my view that I -- the reason why I own 2.5 million shares of Range stock has nothing to do with gas prices. It has everything to do with the fact that I think at some point in time, instead of 1.9 tcf of proved reserves we're going to have 3, 4, 5, 6, 7 tcf of reserves and that's what is going to drive the valuation at Range.

Whether gas prices are $6 or $8 or $7.32. I quite frankly don't care. But I do think at the end of the day it's a commodity business so low-cost consistent approach and the commodity price is going to take care of itself.

That being said I am extremely bullish long-term or moderate term in terms of natural gas over the next five years. It's just to me it's just so compelling. You got natural gas versus cars versus -- gasoline cars throw off 1/6 of the emissions. In terms of generating electricity natural gas is 1/10 of the pollutants that (inaudible) lists.

I mean at the end of the day, we have got to have hydrocarbons for the next 10 are 20 years for whatever transition we are making. The nukes or whatever you want to call it, and the clear winner environmentally in this whole hit parade is natural gas.

So I think we have got the right commodity. I think public policy is going to dictate and I think Americans are willing to pay up a little bit to get a cleaner society and I think it is going to happen. And I think we are right in the middle is and what's clouding it up is the fact that we had a relatively warm winter and we've had a relatively cool summer.

But that's not going to last forever. And every once in a while, there may be a hurricane. So I think once that goes over any look at the macro we are -- I think natural gas is the clear winner in this parade.

Gentlemen, do you have any closing comments?

Well, we've run over a little bit and we really do appreciate all the questions. For those of you all it didn't get a chance to ask a question feel free to call the great Rodney Waller or myself or Roger and the others in our IR team and we will be happy to take some time this afternoon and answer any and all of those questions.

We are obviously extremely excited and bullish where we are at Range and we really appreciate all the support of our shareholders. And you know it's been a great first half of the year in the team and we give all the credit -- I think each one of us around this table give all the credit to the 700 employees we've got. They have just done an amazingly good job and all the hard part this year has been done.

The good news here is with the hedges we've got, the production being up we are going to announce good financial results. The question is just how exciting and how fast can we get some of these emerging plays with a little bit more clarity so we can give that data to you and continue to ramp up the capital on those projects.

So it's a great place to be in terms of position-wise and we are going to continue to stay simple, stay humble, stay disciplined and just keep on doing what we've been doing. We appreciate all your support. Thank you very much.

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