山脈資源 (RRC) 2007 Q3 法說會逐字稿

Welcome to the Range Resources third 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 that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question-and-answer period. At this time I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon and welcome. Range reported results for the third quarter of 2007 with record production in our 19th consecutive quarter of sequential production growth. We're setting records for production and cash flow this quarter. We have a little noise in the quarter with an accounting issue on how we should book our hedging and derivative gains. However, we've furnished to you in the press release table, a table that will walk you through oil and gas sales dollars and volumes, which actually gives you more information than what we've actually disclosed in the past.

The important thing to remember is that Range is collecting millions of dollars from our hedges that we are investing for additional growth in our production reserves every day. Given the volatility in the short-term natural gas prices, it's refreshing to work with a team of individuals who are focused on how to invest more wisely our money than having to spend time on determining what projects to cut back.

In the press release, we have furnished some non-GAAP statements which allow you to compare our results to our historically-reported numbers, which include the Gulf of Mexico operations that we sold earlier this year. On the website, in our supplemental tables for the quarter, we presented in Table 5 a summary of the reported number which correspond to analyst models taking out the nonrecurring and non-cash items. Table 5 shows concisely the amounts which compose the $0.42 of fully diluted earnings per share for the quarter.

On the call with me today 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 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 EDGAR system. 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, 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.

Second, we will be participating in several conferences in the near future. Check our website for a complete listing. We'll be at the JPMorgan Small and Midcap Conference in Boston on November 6th, the Bank of America Energy Conference in Key Biscayne, Florida on November 15th, and the Friedman Billings Investor Conference in New York City on November 28th. We hope to see you soon. Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews third quarter financial results, I'll review some of the key accomplishments so far in 2007. First, as Rodney said on a year-over-year basis, third quarter production rose 13%, beating the high end of our guidance. This marks the 19th consecutive quarter of sequential production growth. Congratulations goes out to our operating teams who did another quarter of a terrific job.

The primary reason we were able to achieve sequential growth in the third quarter was the continued success of our drilling program. For the quarter we drilled 240 wells and undertook 38 recompletions. We continue to be extremely pleased with the drilling results and the rates of return that we're generating from that capital. We currently have 34 rigs running and we're on track to drill about 980 wells for this year, at least by our -- what we've seen, I think we'll be the 10th most active driller this year.

As Jeff will discuss, we've made some very exciting and solid progress with regards to several of our emerging plays. Clearly the foundation of Range's consistent results is our drilling inventory combined with continuing to generate new emerging plays. The 13% increase in production coupled with a 20% increase in realized prices drove a 45% increase in cash flow. The $165 million of cash flow represents the highest quarterly cash flow in our history. To put this in perspective, we've generated more cash flow in the first nine months of 2007 than we did for all of 2006. On a per-share basis, cash flow rose to $1.08, that's a whopping 35% over the prior year.

Looking to margins, due to the 20% increase in realized prices and actual lower unit costs, our cash operating margin for the quarter was up to $5.41. That's up 26% year over year.

As Roger will discuss in more detail, we continue to methodically strengthen our balance sheet. Today we have over $1 billion of liquidity and total debt now is about equal to about the next 18 months of cash flow. Lastly, we're very well-hedged. For the fourth quarter of '07, we have 80% of our natural gas production estimated hedged at an average floor price of $8.36. And for all of 2008, we have 76% of our gas production hedged at an average floor of $8.70. As a result, we're not distracted by the near-term volatility in gas prices and this allows us to continue to focus on what we really think we're good at, and that's driving up production and reserves. All in all, we couldn't be more pleased on what we've accomplished so far in the first nine months of the year and it's a real testimony to the entire Range team. They're doing a terrific job. With that I'll turn the call over to Roger to discuss our financial results.

Thank you, John. Like the first and second quarters of this year, the third quarter of 2007 hit several new record highs for Range. The third quarter brought another record for oil and gas sales, including cash settled derivatives, of $234 million from production volumes that were 13% over last year. As John mentioned, EBITDAX of $184 million and cash flow of $165 million for the quarter were also both new record highs.

Range's average sales price, including settled derivative contracts for Mcfe was $7.79, or 20% higher than the third quarter of last year. Our hedging program increased our average price by $0.78 per Mcfe in the third quarter. Cash margin per Mcfe for the third quarter was $5.41, 26% higher than the third quarter of 2006. Adjusting earnings, as analysts do, for non-cash marked-to-market gains on unrealized derivatives and non-cash compensation expense, net income from continuing operations this quarter was $64 million, double the $32 million from the third quarter of last year.

As Rodney mentioned and listeners will recall, we did close on the sale of our Gulf of Mexico properties on March 31st, 2007. According to accounting rules, the properties sold are deemed discontinued operations, so all year-to-date financial results of the properties sold are distilled into a single discontinued operations line item appearing on the income statement just below net income from continuing operations. The third quarter included just an immaterial post-closing entry from the Gulf of Mexico sale.

Now to assist investors in trueing up their historical numbers and projections, which may include results from the properties we sold, we filed an 8-K on June 19th of this year, which reclassifies prior years of our results from operations for the sale. Now to further assist investors, Rodney's IR team has posted several detailed discontinued operations schedules on both the Range website and in the press release.

Another accounting-driven change to our financial presentation this quarter involves the reclassification of quarterly and year-to-date oil and gas sales revenue earned from our derivatives that no longer qualify for hedge accounting. As disclosed in our filings and discussed on previous calls, our derivatives on Permian and Mid-Continent gas went ineffective in October of 2005 due to a widening historical basis differential between NYMEX and the sales price of the underlying gas. The ineffectiveness was prompted by a mathematical calculation. No changes were made to our hedging practices and no changes were made to the underlying positions.

Once these derivatives were classified as ineffective and no longer qualified for hedge accounting treatment, we were required to refer to them as derivatives instead of hedges and their quarterly non-cash marked-to-market value began to appear as a separate line item on the income statement, labeled marked-to-market on oil and gas derivatives. And as the underlying gas volumes were sold and the accompanying derivative contracts were settled, the cash settlement amounts were recorded in oil and gas sales, the same as we have always done for the rest of our hedge production.

Now to more clearly separate the accounting treatment for our hedges that qualify for hedge accounting and our derivatives that do not qualify, going forward, derivative activity, both realized cash settled derivative contracts associated with current period production and changes in unrealized non-cash marked-to-market derivative value associated with future production will both be shown in the income statement line item labeled derivative fair value income.

Now, income from our hedges, which still qualify for hedge accounting, will continue to be included in the oil and gas sales line.

Now, this reclassification does not impact total revenue, income, or our realized price received from the sale of our oil and gas. It will, however, require readers wishing to track our realized price to flip over to the MD&A section for a breakdown of these two derivative fair value income line components.

Now, we're still able to use hedge accounting for our Appalachian gas hedges and most of our oil hedges. However, as you can see, the accounting and reporting requirements for hedge accounting have become increasingly more complex. So we are considering a change to full-time -- or full marked-to-market accounting in the future.

Now, the operating cost story for 2007 remains a good one with third quarter direct cash operating costs of $0.92 per Mcfe, identical to the year-to-date nine-months cost figure. Production taxes were slightly lower per Mcfe, coming in at $0.38 for the third quarter, $0.01 below the first two quarters of 2007. Our prior quarter mid $0.90 per Mcfe operating cost guidance figure for the remainder of 2007 still holds.

Regarding corporate overhead costs, G&A expense per Mcfe for the third quarter, adjusted for non-cash compensation expense, was $0.44, level with last quarter, but up $0.13 from the third quarter of 2006. About half of this increase may be attributed to Appalachian Basin hiring for the new Pittsburgh and also expanding our Virginia team. G&A expense per Mcfe is anticipated to remain in the mid $0.40 range for the fourth quarter.

The Range stock price increased from $37.41 at the end of the second quarter this year to $40.60 at the end of the third quarter this year. This contributed to a non-cash deferred compensation plan expense figure of $8 million for the third quarter. This non-cash expense stems from the quarterly marked-to-market adjustment of securities held in the employee deferred compensation plan. During the third quarter of 2006, when the stock price was $25.24, this expense was actually a $3 million credit.

Now, the press release tables do contain a breakout of all non-cash compensation amounts included in these various expense line items, and that'll enable investors to better attract analyst consensus estimates. Also a function of our stock price was the decision during the third quarter to repurchase 155,500 shares of Range stock into treasury at an average price of $34.30 per share.

Interest expense per Mcfe in the third quarter was $0.66, reflecting higher rates and higher debt levels as we funded the Nora Field acquisition late in the second quarter. For the rest of 2007, our interest expense per Mcfe will be in the $0.66 to $0.69 range. Exploration expense adjusted for non-cash compensation was just over $5 million in the third quarter of 2007, roughly half the exploration expense that we incurred during each of the first two quarters of this year, and it was $10 million lower than the prior-year period. Now, dry hole costs of only $173,000 for the quarter is responsible for the decline. It's always difficult to predict drilling results, but exploration expense in the fourth quarter will likely be in the $12 million to $15 million range.

The DD&A rate for the third quarter was $1.90 per Mcfe, compared to $1.81 per Mcfe in the second quarter and $1.80 per Mcfe in the first quarter of this year. Included in the $1.90 third quarter DD&A rate is a $0.06 per Mcfe or $1.7 million unproved acreage impairment taken in the Gulf Coast division. The DD&A rate for the remainder of '07 should be in the $1.85 to $1.90 per Mcfe range.

The income tax rate for the third quarter has returned to the 37% level, following a one-time reduction in the effective rate last quarter due to a state tax credit. Current income taxes during the third quarter totaled $133,000. Now based on our current level of income and capital spending, we anticipate paying no significant cash federal income taxes going forward in '07. Our intangible drilling cost deductions are sufficient, without utilizing our $216 million NOL carry-forward, to shield both ordinary income and the gain from the Gulf of Mexico sale. However, we may elect to use a portion of the NOL later this year to offset the gain as part of our overall tax planning strategy.

As we mentioned earlier, EBITDAX for the third quarter was $184 million and quarterly cash flow was $165 million, both new record quarterly highs. Cash flow per share for the third quarter was $1.08, up $0.04 per share from the second quarter of this year and up from $0.80 or 35% from the third quarter last year. Cash flow per share is $0.05 higher than the first call consensus estimate of $1.03. Net income per diluted share for the third quarter calculated in a similar manner as the analysts is $0.42, up 83% from last year and $0.03 over the first call consensus estimate of $0.39.

Year-to-date financial results pretty much mirror the quarterly results, with production up 17% and average sales prices up 15%. Nine-month year-to-date EBITDAX was $538 million, up 38% compared to the $391 million figure for the first nine months of last year. Cash flow for the first three quarters of this year was $484 million, 38% higher than the $351 million figure from 2006. As John mentioned, cash flow for all of 2006 was $466 million, so we've already generated $18 million more cash flow in the first nine months of '07 than we did in all of 2006. As Rodney mentioned, full reconciliations of these non-GAAP financial measures to GAAP are available on the Range Resources website.

During the third quarter of 2007, Range began to layer in its first gas hedges for '09 and added to the volumes hedge for '08. Range has established a weighted average floor price for approximately 76% of its '08 gas production at $8.70 per MMBTU and approximately 33% of its '09 gas production at a weighted average floor price of $8.14. As for our remaining '07 gas production, we have an estimated 87% of this production hedged with an weighted average floor price of $8.36 per MMBTU. Also in the third quarter of '07, Range began to more actively manage its gas price basis exposure by entering into gas basis swaps for the next two years on some of our Permian, Mid-Continent, and Appalachia production. Range's hedging position may be viewed in greater detail on the home page of our website.

The balance sheet was fairly quiet in terms of major leverage changes with our debt-to-cap ratio coming in at 39% flat with last quarter end. However, we did implement two changes to our liabilities structure during the quarter, both of which served to enhance our financial flexibility going forward in what has become a somewhat turbulent credit market compared to prior periods.

On September 28th of this year, we issued at par 250 million of senior subordinated ten-year notes bearing a fixed interest rate of 7.5%. Concurrently with the note issuance, Moody's upgraded Range's corporate credit rating to BA2 and its senior subordinated note rating to BA3. This is the second rating agency upgrade Range has received in 2007 and reflects the continued value-added growth of the company and improvements in our overall credit quality. Proceeds of the note issuance were used to reduce the outstanding balance of the floating rate bank debt to $266 million at quarter end. This balance outstanding provides $634 million of committed liquidity under the bank line of credit.

Just this past Monday, October 22, the Range Bank Group approved an increase in that credit facility borrowing base from $1.2 billion to $1.5 billion and a one-year extension of the credit facility maturity to October of 2012. The $1.5 billion borrowing base is based upon our existing assets and provides additional funding capacity should the need arise. One of the lessons we learned from the credit and capital markets during the summer of 2007 has been not to take timely, favorable market access for granted. This is a lesson we have heeded with these two enhancements to Range's financial flexibility.

In summary, the third quarter produced record production volume, record oil and gas sales, including cash-settled derivatives, record EBITDAX, record cash flow, and another rating agency upgrade. Cash margins remain high thanks to our hedging program and stable cost profile. With year-to-date cash flow and EBITDAX already exceeding the full-year '06 totals, we're not only on track for another record year, we've already partially achieved one. John, I'll now turn it back to you.

Thanks, Roger, nice report. I'll now turn the call over to Jeff Ventura to review our exploration and development activities. Jeffrey?

Thanks, John. I'll begin by reviewing production. For the third quarter, production averaged 326 million per day, a 13% increase over the third quarter of '06 and a 4% increase over the second quarter of '07. This represents the highest quarterly production rate in the Company's history and the 19th consecutive quarter of sequential production growth. For all of '07, we expect to achieve 16% production growth.

Let's now review three of our key projects. First I'll start with the Barnett Shale (inaudible - technical difficulty). Our first Ellis County well has been completed and went online at a rate of 1.5 million per day. However, due to poor hole conditions from sidetracking, Range was not able to optimally drill and case the horizontal lateral of the well, which compromised the completion of the well. The initial rate is within expectations of 1 to 3.5 million per day and we believe there is prospective and has upside. Given that this is our first well in the area, we spent a lot of time and effort figuring out how to optimally drill through the complex section of the holes above the Barnett. Despite the drilling and completion problems, we still ended up with a 1.5 million per day well.

On the positive side, the Barnett is more than 300 feet thick and productive. We also feel that we now know how to better drill and complete a well in this area. I have complete confidence that if the area has good productivity and we end up with more than 200 wells to drill, that by wells four, five, or six, our drilling and completion teams will have solved the problems of how to optimally drill and complete a well on our 20,000 acres in Ellis County.

In total, we have 90,000 net acres in the Barnett. Our Barnett production is now 66 million per day net and growing. We expect to exit the year at a rate of 75 million per day. We entered the year producing 30 million per day, so we will have more than doubled production during the year. Importantly, we did not have to significantly increase our rig count to do so. Currently we are running five rigs in the Barnett. The fact that we've been able to significantly increase our production by only running five or six rigs speaks to both the quality of our acreage and our team.

Another very impactful, low-risk project for us is our Nora area located in Virginia and the Appalachian basin. This project potentially could double range by itself. There is significant upside to all three horizons in Nora, Coal bed methane, tight gas sands, and Devonian shale.

Starting with the coal bed methane, there is 2.4 Tcf of gross gas in place in this prolific field. If we can achieve a 70 to 80% recovery of the gas in place, gross reserves would be 1.7 to 1.9 Tcf. Net the range we have left to recover 0.8 to 1.0 Tcf. Only 200 Bcf of this gas is currently booked, which gives us great low-risk upside. This upside will be achieved through continued development and infill drilling and recompletions. Importantly, our historic development costs here are well below $1 per Mcf.

The second key horizon is a tight gas sands below the coal bed methane. These Mississippian age zones exist from 3,000 to 5,000 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 F&D costs. The tight gas sands well have historically been drilled on 112-acre spacing. This year we'll test down spacing in this horizon. Based on 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 if infill drilling is successful. Combining the coal bed methane and tight gas sands, we potentially have about 6,000 wells to drill.

The third key horizon is the Devonian shale, which is from 5,000 to 6,000 feet deep. Nora is about 10 miles east of the 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 Nora acreage position and historically was completed and commingled with the tight gas sands in more than 90 of the existing vertical Wells.

One of the vertical wells has produced $1.4 Bcf after being stopped with nitro back in the 50s and is anticipated to produce 2.2 Bcf. We plan to apply new technology by drilling horizontal wells and completing with multiple stage foam fracs. If successful, it could add over 1 Tcf net the range. We'll be actually spudding our first Nora horizontal well today.

Another high-impact opportunity for Range is our Devonian shale play in the northern part of the Appalachian basin. Although this product has higher risk, it represents another opportunity to more than double the Company by itself. The Devonian shale represents 2.5 to more than 5 Tcf of upside potential and currently we have more than 500,000 net acres in the play.

During our last conference call in July, I discussed that we'd be focusing on three items, verifying that we could drill and complete our vertical wells for $900,000, drilling more horizontal wells to better understand how they'll perform, and testing all of our key areas by the end of this year. Let me go through each of those three things.

First, in regards to the vertical wells for our low-cost vertical pilot, our goal -- we thought in a development mode we can drill and complete the wells for $900,000. The good news is that after drilling ten wells in our pilot, not only did we meet the $900,000 goal, but we actually beat it. It looks like we can drill and complete the wells for $850,000 and I really believe we can improve on that in time. Also historically, I've talked about the first three wells and their performance. At this point, we've got 38 vertical wells with history and that's very early in terms of that, but if you include every single well, all 38 from the best to the worst, our current best estimate average of those 38 wells is 700 million cubic feet per well gross ultimate recovery. Given that we have 100% working interest and an 86% average NOI, our cost to find and development across all 38 wells in a development mode would be $1.41 per Mcfe. So very good finding costs.

Then, importantly, I think if you look at that going forward, I think there's a good chance that we'll continue to drive costs down. Again, if you've got a good, high-quality team and you let them do the same thing over and over, they tend to get very good at it and we have a high-quality team and multiple opportunities here. And then in terms of the reserves, I think there's -- I'm hopeful that we'll also be able to increase the reserves. First of all, on those 38 wells that I mentioned, we did lots of experimentation on how to drill and complete. Obviously, some things worked very well and others things when you experiment don't. But the numbers I'm giving you are the good, the bad, and the ugly, that's the average of everything.

So as we go forward, obviously we've learned a lot, and we're going up the learning curve. The second thing that also includes multiple areas. Going forward, we can also our high grade our reserves by drilling in better areas.

Let me move forward and talk about horizontal drilling. There, we're also making significant progress and I'm very excited that. We talked about sequentially the rates on our horizontal wells and particularly the last well at 3.2 million per day equivalent is really a strong producer. So I'm very excited about that. The team's making great progress in terms of learning how to drill and complete horizontal wells. Currently have two rigs drilling horizontal wells there.

If you step back and think about it, again I've mentioned it before, but based on both analogy and theory, it should turn into a horizontal play. If you look by analogy to the three big shale plays, the Barnett, the Fayetteville and Woodford, all three of those ended up being horizontal. Again just theory, more cross-sectional area you open to flow again should turn horizontal, but I'm encouraged by what we're seeing vertically and I'm also encouraged by what we're seeing horizontally.

The last of that was by the end of the year, we wanted to make sure that we tested all of our key areas, and that's not only in Pennsylvania, but also down in Virginia and West Virginia. And the good news is we're on track to do that and by our next call, we should be able to talk some about that. Moving on to the Mid-continent, there's two particular projects I want to mention there and they're both Granite Wash plays.

The first one is a horizontal play in the Texas panhandle. Importantly, there, we drilled our first two wells and excellent results on both. One of the wells came online at 3 million per day and the other one at 2.8. Per well cost is about $2.9 million to drill and complete and our current estimate of reserves is about 2.4 Bcfe per well. So a great F&D, great rate of return. The second Granite Wash play is in Oklahoma, where our first vertical well came online at 2.4 million per day. And the per well cost here is about $2 million to drill and complete. We're currently estimating reserves of about 2 Bcf. So again, great rate of return and finding costs. Between the two areas, we potentially have more than 250 locations to drill. And our working interest average is about 48% in these two areas.

We also 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 Tcf, primarily in low-risk, coal-bed methane, shale gas and tight gas sand plays.

So we can grow the Company potentially four to five times based on what we currently have identified. We have a great track record of converting that to value for our shareholders, so Range is exactly where we want it to be. We're a low-cost producer with a lot of low-risk, built in growth with great hedges in place.

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

Thanks, Jeff. Terrific report. Now let's look to the future a bit. In terms of fourth quarter and what we anticipate, we continue to see very strong operating financial results. We're looking for fourth quarter production to come in at approximately $333 million to $335 million a day on an equivalent basis.

On the price side, assuming current futures prices and hedges, we anticipate fourth quarter realization after hedging to be in the $7.85 per Mcfe range. That is a significant increase over the prior-year period of $1.28 or 19% and it's $0.06 higher than the third quarter of '07. So we should see higher prices in the fourth quarter. Due to higher production in prices, we again anticipate fourth quarter revenues, cash flow, and earnings to be substantially higher than the prior-year period.

Based on the results for the first nine months of the year, we're well on our way to achieving our 16% production growth target for 2007 due to the higher volumes and prices and having stable costs, our cash flow from operations for '07 is anticipated to increase by an amazing 40% over 2006. So for the year, we anticipate record production, record revenues, cash flow, and earnings while ending the year with a far stronger balance sheet.

So you can see, we're pretty excited about 2007. It's really shaping up to be a tremendous year for Range and our shareholders. While focused on getting our wells drilled and hitting our quarterly production targets, we also continue to expand our drilling inventory and we're making solid progress with our emerging plays.

As you've heard from Jeff our technical teams are making some pretty exciting progress in terms of some of those plays. Today we've got the largest drilling inventory in our history with over 10,000 projects. Our inventory, together with our emerging plays, represents 8 to 11 Tcf of future growth potential. We believe that we're kind of unique in that for our size we have a very large, transparent drilling inventory forecasted on a very large 3 million acre leasehold position, which again is pretty unique given our size.

Lastly, looking to the next 12 months or so, it's going to be a very exciting time at Range. In view of the drilling inventory, the cost structure, and our strong hedge position, we're quite confident that we'll deliver record financial results. As a result, we're focusing our time and effort on projects that are really going to drive our evaluation. This includes some of the projects Jeff talked about like the eastern extension of the Barnett, some of our Hill County acreage in the Barnett play, the tremendous CBM tight gas and shell potential at Nora, the Devonian shale project in Appalachian and the Granite Wash play, as well as a number of other projects that our teams are working on. On many of these projects, we should continue to see meaningful clarity over the next several quarters, so I'm confident one or more will be successful in terms of driving our evaluation higher.

Assessing our emerging plays, we're extremely pleased with the progress we've made so far in 2007. In the Barnett Shale play in Ft. Worth, production has more than doubled so far this year. Our acreage position has grown from 55,000 acres at the beginning of the year to 90,000 acres currently and our first well in the eastern extension project found a nice, thick, three hundred-foot thick plus section of Barnett, so we're very pleased.

At Nora we completed the incremental add-on acquisition in May, thanks to Chad and his team. Production is up to over 100%, our 30-acre CBM down spacing program is showing excellent early results and we just kicked off our tight gas sands program and today, as Jeff mentioned, we're spreading our first horizontal shale test at Nora.

In the Granite Wash play, we've drilled three excellent producers and will drill another six wells by year end and we've identified over 250 locations on this acreage and we're continuing to lease the acreage and build that acreage position. So that's pretty exciting.

Lastly, our Devonian shale play, we've increased our acreage position so far in the first nine months of the year by over 100,000 acres. Our low-cost vertical program is making excellent headway and we've recently drilled a breakthrough horizontal well at IPed for over three [million] a day.

If you had told me at the beginning of the year that we would have made this kind of headway on these plays in the first nine months of the year, I would have said that you were either crazy or overly optimistic, at least. So again I think it gets back to having a world-class technical team and a clear focus on what we're trying to accomplish.

I've said it before and I'll say it again. The reason you should invest in Range is not because you think commodity prices are going up, that we're going to consistently increase production and reserves per share over the next several years at top quartile finding costs. It's a pretty simple strategy that's hard to execute. With that, operator, why don't we go ahead and open up the call for questions from those on the call.

Thank you. (OPERATOR INSTRUCTIONS) The first question is from Shannon Nome with Deutsche Bank. Please go ahead with your question.

Good afternoon, everyone.

Hello, Shannon.

Congrats on a great quarter. Jeff, on the Appalachian Shale, the horizontal that came on at 3.4 million a day, how is the production, I guess -- how is the production, how long has that been on and how is the production holding up since and what are the cost parameters around those, you think?

The well has been on for over 60 days, about 65 days. Production's holding up extremely well. So it looks like it's really a strong producer, very excited about that. And in terms of cost, I think before we address costs, we'll probably do with a we did with the verticals. In these early wells, there's a lot of experimentation. Probably, I would say on the next quarterly call, we'll give you our estimate in a development mode of what those wells will cost. But just to put some rough guidelines around it, the wells we're drilling there vary. They're going to be roughly 6,000 to 7,000 feet deep and in terms of drilling and completion, not unlike parts of the Barnett that are at those similar depths. But it's a little early for us to come out with numbers, but we definitely will. I'm excited by -- we've made clear progress from well to well to well and 3.2 million for 60 days producing like it is, I couldn't be happier. I just hope we continue to replicate that and hopefully even improve on that.

Fantastic. The other thing is on the Nora field shale well that you're spudding, I noted that on the Equitable call, they increased their high-end estimate for their EURs on their horizontal shale wells and wondered what your -- I guess, what your expectations are for some of those wells in that part of the world?

Our expectations -- the best thing to look at would be their wells. We're literally just across the state line and just a little bit deeper. So they should be similar to what they're doing and I guess we'd be thrilled with that and maybe even a little bit potentially on the high side in that they're a little deeper and might have a little bit more pressure. But the analogy in the way we're going to drill and complete, in terms of IPs and reserves, that will be the best place to look. They're also our partner, we're working closely with them, and that's been a very good relationship there.

Very good. One final thing for John, pardon me if I missed it, but have you provided any early read on '08 CapEx as it might look relative to '07, or are you still in budgeting phase?

Shannon, we're going to spend about $890 million this year. We'll spend -- knowing our technical team, they'll want to spend more next year. So my gut feels it will be higher. How much higher, at this point in time, we're just into that and we're running numbers. And a lot of it's really going to depend on -- it's pretty simple math here. We're going to take our estimated cash flow -- the good news is that we've got a lot of it hedged, so that part of it is not that difficult to determine, and then we'll take that CapEx number and then the delta there will be the asset sales that Chad and his team need to execute. So that's kind of the formula.

The good news is, at least the projects we've seen is, at least from Jeff and my perspective, maybe not so much from the division's, but from Jeff and my perspective, we've got a lot of projects that meet our hurdle rates. So it's going to be a real challenge to pare those down. We're probably going to pare it down 3 or 4, $100 million to get to a number that I feel good about.

The good news is we've got -- in terms of the portfolio, we've got a lot of strong projects, so we'll be able to pick the best out of that litter, so to speak. So the good news is we've got really some nice projects, high rates of return given our hedges. So it's the perfect position that Jeff and I want to be in, in that way, in terms of being able to have to discriminate against these projects. Again, a lot of it has to do with what kind of risks we're taking, reserve life. Obviously, we want to continue to focus on the portfolio, make sure we have a good spread of capital expenditures across a reasonable number of projects and not put all of our eggs in one basket. But the good news in all that is that, at least from what I've seen on a preliminary basis, it looks pretty exciting, but we'll come out next quarter and give you a number. But my gut feel is that it will be higher than what we're spending this year.

Thanks, John.

The next question is from David Tameron with Wachovia. Please go ahead with your question.

Hi, John. A quick question for you, and maybe this is a Jeff question, I don't know. But in the Devonian frac, can you talk about what volume-sized frac you did and compare it to kind of some of the things you're doing in the Barnett?

That's the part that we will keep confidential as long as we can. Clearly, in the terms of the shale plane the northern part of the basin, the Marcellus, we've drilled and completed a lot more wells by far than anybody else in the industry. We've got the dominant acreage position, so because we're still able to grow that position and because it's such an important play, how we drill and complete the wells is something we'll keep confidential as long as we can and we'll take maximum advantage to do the right thing for our shareholders so that we can create the maximum gain for the shareholders. But that we'll keep confidential.

Okay. Maximum time, does that mean fourth quarter, if you give us well costs in the fourth quarter --

We could keep it confidential for ten years and I don't think the whole thing will do that. I don't think we can do that, but we'll keep it confidential as long as we can.

Let me come at it a different way.

What we will do, though, as we continue to drill wells, we'll tell you the initial rates and give you a feel, probably next quarter, for what the cost to drill and complete is and probably some range of reserves. We'll continue to come out with information because we want to make sure we're relating that and getting the Company fairly valued. How we exactly achieve that in terms of lateral lanes and stages and profit pipe and where do we land them and what counties, that's the stuff we'll keep confidential as long as we can.

Okay. Let me see if I can get this a different way. Second well versus the first well, what did you do different?

That would be how we drilled and completed it.

Okay.

You can try.

Let me -- let me move on. The Floyd sale, what's the latest and greatest coming out of the Floyd? Where are you guys on that? I know everybody's pulled back a little bit, but can you talk about where you are?

Yeah. And let me put it in perspective by saying that we're in five shale plays, and that's counting the Devonian and Barnett and then we've got some exposure to the Woodford and the Ardmore Basin and then some stuff in the Permian and Floyd. Clearly on the Devonian Shale and Barnett, we feel we're leaders and we want to stay that way. The other three, we're clearly followers. So in the Floyd, we've intentionally gone slow. However, we did just drill our first vertical well and we're in the process, by the end of the year we'll have it completed. Our plan is to go slow. We've targeted a different part of the Floyd than everybody else has.

We're in a different part of the basin. We believe we're in a stack pay area. So we think what we're doing is significantly different than what other people are doing, but we've got long-term leases, we've got basically ten years to figure it out. We're going to be slow and methodical, learn from others, and that's sort of where we are in the Floyd. So by the end of the year, we'll have our first vertical well completed and based on that and we're -- like John said, we're in the process of building a budget for next year. We may come back with one or two wells next year, something like that.

Last question, Barnett, big picture '08, where are the rigs going to be, what's going to be the focus? Can you give us a little bit of color of what you're looking out 12 months?

Again, we're putting that together right now as we speak. We're currently at about five rigs and we're going to end the year at five rigs so therefore we'll enter next year at five rigs and we're putting that together now. You'll see some sort of ramp-up in that. But the good news again is with the quality of acreage and teams we have, we had significant growth this year and we think we're going to get significant growth next year and on into the future. So it will be a continued development of the properties we have, which are strong and still have got lots of development in the core areas that work for us.

Plus, obviously, we'll be looking at can we extend it some to the east in Ellis and what will that be like and can we extend it some to the south into northern Hill County, where the industry currently has about 12 good Barnett producers so far. At least wells with initial rates in that 2 to up to 3.5 million per day range.

So that's where we are, but again it's early, we're building our program for next year, and sometime probably in the early fourth quarter -- or first quarter of next year we'll come out with capital spending and give you all that detail.

Okay. Thanks and congrats on the progress thus far this year.

Thanks, Dave.

The next question is from Nicholas Pope with JPMorgan. Please go ahead with your question.

Hey, guys. Was hoping you could give a little detail on how you are going to go about proving up your acreage position in the Devonian shale in the next several years? Just a bigger picture kind of view. How you're going to prove everything up out there?

Yeah, let me -- this is John. Let me take a shot at it now at a kind of higher level, and then I'll let Jeff kind of fly a little lower. I think as Jeff mentioned, we're really focused on three activities there. One is trying to codify what we can drill these vertical wells for. What that really does is -- if we can drill them into that 800, 850 range or let's say under 900, you've clearly got an economic play in terms of the areas where we've drilled those wells, so that gives you confidence that at least you can do that and you can make some pretty good money.

Our hope is like the Barnett and Fayetteville and these others is that it will turn into a horizontal play, because that will allow you to grow reserves and production at a faster rate and the horizontal wells clearly have a higher economic return, if we can do the things we hope to do.

The last thing that Jeff mentioned is that by year end we will have at least one and in most cases two or three wells drilled in each of our acreage blocks that we've developed out there, and that's really important.

And to give you a perspective, the Barnett from north to south is about 120 miles, whereas the Appalachian basin a about 1,200 miles. So you've got a much bigger sandbox, which is good news because you can buy lots of acreage. The bad news is you can buy -- not all of it will be productive, commercially. So just like in the Barnett, the acreage in Johnson County is worth a heck of a lot more than the acreage in Erath County.

So what our goal is -- and this again gets back a little bit of our competitive advantage, is to get out there as early as we can and really drill up stuff so we can find the Tarrant and Johnson County type acreage in the Appalachia Basin versus the Erath County acreage. So that's the real challenge and again that's what we're doing and that's what we're going to be doing with a lot of this vertical drilling. And we're in the process of doing that, drilled some good wells in some of the other areas and we're testing those right now. And what that will allow us to do is as we start to define those areas, we'll move these land men that we've got running all over the basin and we'll focus in different areas to build our acreage positions in some areas faster than others as we start to hydrate the acreage position.

Again, that's the key thing. In the Barnett, if you didn't know that Tarrant and Johnson county was going to be the best, you would have spent all your time there and leased as much acreage there and you wouldn't have spent in time in Erath and Bosque and Somerville and the rest of these places. So that's kind of where we are. The challenge is, it's a really, really big sand box, so we have to be a little careful here. But the good news is acreage is still relatively cheap, still less than $200 a acre in most cases, still [age] royalty, still five-year leases with no drilling commitments.

So in terms of holding the acreage that we've got, again we've got five years with no drilling commitments. And not all of it will be good. And one of the reasons why we've kind of said we've got 500,000 acres plus is that we've got a fair amount more than that, but we think over time we'll condemn acreage and we have already, but we've also bought in other areas we like better.

So we're going to -- instead of going up and down and up and up and down again in term of acreage counts, we're just going to stick with the 500,000 plus. Over time then, as we find areas that we are going to go more into the development mode, then we'll pull those out and then we'll start separating out and giving you some clarity in terms of the quality of acreage and which is in the development mode and which is still in the R&D mode. And again we'll start doing that probably a little bit at the year end conference call and more as we go through in terms of 2008.

I would just add a little bit to that. We've got Devonian shale plays obviously in the northern part in the Marcellus up in Pennsylvania and in the southern into [Yuron].

The acreage we have in the northern, like John said, is more than 500,000 acres. John mentioned we've got good terms. Some of those are five-year leases, some of them are seven-year leases. Some of it is HPB, because that's historically where the roots of Company are, HPB by other horizons.

So all of that's important and obviously as we're stepping out and hydrating areas and vertical wells with the economics that we have, you've got good economics on a vertical well to learn about an area and then quickly we'll move in and try horizontal in the better areas. And then in the southern part of the basin, we've got another 390,000 acres gross, plus or minus, in Virginia and West Virginia and that's all -- we own the minerals. So we'll have it in perpetuity. So we're in great position there.

Thanks, guys.

The next question is from Jack Aydin with KeyBanc Capital Markets. Please state your question.

Hi, guys. Jeff, in Nora, and you mentioned about 2.4 Tcf CBM potential reserve. Is that -- could you tell me based on what is spacing? And the next question is basically, if you go from -- I don't know where is spacing right now across the field, but if you go to the 30-acre spacing, how many locations would you end up having there?

Let me clarify, with the CBM, there's 2.4 Tcf of gross gas in place and it's pretty well defined because you have basically 1,700 control points that you're mapping from, just on your acreage. So you've got a great tank of gas and, like I said, with reasonable recovery factors, we've got gross reserves of 1.7 to 1.9 left to recover somewhere between 0.8 to 1.0 Ts of which only 200 is booked. So you've got a significant amount of gas left and a lot of it is unbooked and it's going to come in at less than a dollar. And that's gas in place. How are we going to get that? We've got currently on the order of 2,700 existing locations at 60-acre spacing and then obviously if you down space, you could roughly -- and plus there's already 1,000 wells on there, you can more than double that number.

With the 30-acre spacing, we've drilled a number of the down spaced wells. They look attractive and they're looking good, plus you've got the whole opportunity with the tight gas sands below and then the shale below that. So you've got on the order of probably 5,800 -- 5,500 plus CBM wells to drill and then when you add the tight gas sands wells in, easily probably 6,000 wells to drill.

So huge inventory, production out there has historically grown well and it's grown in some of the best finding costs not only in our Company, but in the industry if you look at that. So low lift cost, doesn't make a lot of water, so you get great finding costs and low lift costs, so the best of both worlds.

Okay. On the Floyd share, in the Floyd area, is your acreage, where you're drilling, is it in the Mississippi area or the Alabama area?

It's in the -- it's primarily in the southern part of the basin and it's -- I'd guess people that have been in our offices have seen some of those maps, so it's on the Alabama side in the southern part. But it's away from where -- south of most of the drilling has occurred. It's a different area, it's we think a stack play area. So it offers some things that are unique, but again it's a higher-risk play. We're going to go slow, we've got ten years on our leases. And the other neat thing about that, we put it together for very low acreage cost. So literally all in, roughly $30, $35 an acre for five-year leases with five-year kickers. So we've got a great position and hopefully in time it will prove up. If not, the risk capital is low and the reward is high.

Thanks a lot.

Thank you.

We are nearing the end of today's conference. We will go to Marshall Carver of Tudor Pickering for the last question. Please go ahead with your question.

Thank you. Had a couple of questions. One, you mentioned that the 3 million a day well, horizontal well in Appalachia, was holding in at pretty good rates. What about the two other wells? Do those seem to have less declines than you would see, say, in the Barnett?

Again, it's very early but I would characterize that the decline profile seems to be probably different -- clearly different than the Barnett and it's early and we're not based on a lot of wells, but they're holding in fairly well.

Okay. Any feel for drilling plans for '08 in Appalachia, or is it too early for that yet?

Yeah, we're really building our whole budget for all areas and we're well in the process of putting that together and then we need to fine tune it and obviously get board approval and typically we announce that in January of next year. But we're putting all that stuff together right now.

Thank you. Last question. I know you're doing some exploration -- Woodford exploration in the Ardmore basin and also some east Texas exploration near Glen Rose. Any results on those yet, or is that later on in the year?

In the Ardmore Basin, we've just -- we're just flowing back our first horizontal well and by the end of the year, we'll probably have two more and we'll probably have a couple of vertical wells. So on the first -- or fourth quarter call, we'll be able to give you updates on all of that. We ought to have some good information in terms of that and the stuff in east Texas is really one well so far and it's early on. That's something again we'll probably just talk about next year.

Okay. Thank you very much.

Thank you.

Thank you. I would now like to turn the call back to Mr. Pinkerton for closing remarks.

Well, thank you all for joining us. We're obviously pretty excited about what's going on at Range. I really wanted to congratulate our teams in the different divisions for doing a terrific job.

Again, I think when you look at Range, I think the bottom line is the portfolio of projects that we've got and we didn't talk about, we've had a couple of good discoveries over the Mississippi, we've had a nice discovery well that we just drilled up in western Oklahoma that came on over 3 million. So because of lack of time, we could spend all day talking about some of the [real] results when you're drilling almost a thousand wells a year.

So the good news is we've got a big portfolio, as Jeff mentioned, and most of its pretty low risk, pretty well defined and the real -- I think the real bedrock in terms of future finding and development costs is Nora where we're going to be drilling wells and finding gas from in the $1 per Mcf. So that will be the anchor that we'll use to hopefully continue to be one of the best performers in terms of low finding and development costs year over year over year. So that really gives a competitive advantage and it's one that obviously we've spent a lot of time and effort on and one that we hold very dear. So that really sets it out.

I think from our perspective, '07's pretty well done. It's going to be just a tremendous year and we're really focused on these emerging plays and some of the other things in terms of building on those as we move forward. I think the -- as I mentioned a few times before, I think the real -- the real key is we need to drive -- continue to drive production and reserves per share up.

We've got a great portfolio and we can do that with the existing acreage that we've got. How we fund that, I think, as I mentioned, will be a combination of asset sales coupled with our cash flow that'll fund our expanding capital program. I see no reason to issue any equity in the future unless we were to do a sizable acquisition and just given the market for acquisitions, because we're in there looking every day, I just don't see anything on the horizon, given the competition, especially from our little MLP friends -- so I think we'll be relatively quiescent on the acquisition side.

Again, I've said it before and I'll say it again, these emerging plays are starting to really percolate to the top. And given that I'm the largest individual shareholder, I really want our existing shareholders to fully benefit from these emerging plays and what we've done over the last two or three years. So we're going to be very cautious in terms of doing anything outside the sand boxes we're already in. We're going to be very disciplined, just like we've been over the last several years and really drive that value for our existing shareholders. So I think that's the real strategy, the real focus at Range over the next 12, 18 months.

But it's an exciting time. I think -- I think it's -- I think the next ten years is going to be the golden era of natural gas, which is trading at a 50% discount to crude oil, I think capitalism will take care of that over time. So I think natural gas prices, while they're very volatile in the short-term, I think there's a high likelihood that they'll be higher two years from now than where they are today and three years from now. I think that bodes very well for us in our business.

So it's an exciting time and an exciting company and quite frankly, it's an honor to be associated with Range and all the great people we've got. It's a real pleasure. And I really appreciate it and take it to heart. With that we'll conclude the call and we appreciate all the questions. If somebody has a question you didn't get to ask it, feel free to call any of the four of us and we'll be happy to answer that question this afternoon or tomorrow or the next day. Thanks again.

Thank you for your participation in today's conference. You may disconnect at this time.