山脈資源 (RRC) 2006 Q3 法說會逐字稿

Welcome to the Range Resources Third Quarter Earnings Conference Call. This call is being recorded. All lines have been placed on mute to avoid 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 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 continues to report outstanding results, and as expected, we on track for reporting record results for 2006. The third quarter is highlighted by our highest production in the Company's history, with impressive growth coming out of the Fort. Worth Barnett Shale, our Nora CBM properties, our Permian Basin properties and the Marrow/Springer Wells in Oklahoma. We continue to focus on executing our business plan to grow production and reserves at top quartile findings and list costs. With our current hedge position we feel that we can be assured of the operating cash flow needed to execute our plans to 2007 and 2008. We're happy to discuss our results with you today.

On the call today with me are John Pinkerton, President and Chief Executive Officer; Jeff Ventura, Executive Vice President and Chief Operating Officer; Roger Manny, Senior Vice President and Chief Financial Officer, and Charlie Blackburn, our Non-Executive Chairman.

Before turning the call over to John, I'd like to cover a few administrative items. First we did file our 10-Q this morning with the SEC' 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, EBITDEX, cash margins and the reconciliations of our non-GAAP earnings to reported earnings that are discussed on the call today. Details of our hedge position are also posted on the website.

Second, Range will be speaking at the Merrill Lynch High Yield Conference in Las Vegas on November 14; the Bank of America Energy Conference in Florida on November 17, and the Friedman Building's Investment Conference in New York City on November 28. All of our conferences are posted on the website along with scheduled road shows for your information.

Now let me turn it over to John.

Thanks, Rodney. Before Roger reviews the third quarter financial results, I'll take a few minutes here to discuss our key accomplishments in the quarter.

First, overall we're very pleased with the third quarter results. On a year-over-year basis production rose 19% beating the high-end of our guidance. This also marks the 15th consecutive quarter of sequential production growth. To put this in perspective, we analyzed all the E&P companies with a market cap between $1 billion and $10 billion and Range was the only Company with 15 consecutive quarters of production growth. We view this as quite an achievement and believe this directly reflects the quality of our asset base and the talents and the determination of our organization.

On the drilling side, our drilling program is on schedule; it has been throughout the year. Through September 30 we've drilled 760 wells. We're very pleased with the results and we're generating very attractive in the first six months of 2006. We continue to be very pleased with the drilling results and we're generating very attractive rates of return. In the fourth quarter, we plan to drill another 243 wells, giving us 1,003 wells for the year.

On the cost side of the business, the third quarter saw both positives and negatives. On the positive side, we were able to hold third quarter G&A expense per mcfe level with the prior year and reduced it $0.04 for mcfe compared to the second quarter. On the negative side, direct operating costs increased $0.18 per mcfe versus last year, and they're $0.08 higher than the second quarter.

Bottom line, however, our cash margins remained a very healthy $4.29 per mcfe and importantly our cost structure continues to be one of the lowest in our peer group and Jeff and our operating teams are being proactive on the cost side.

Next, by posting the production volumes that we have and the solid results we've had for the first 9 months, we've set the stage for what we believe is going to be a terrific year for Range and our stockholders. To put this in perspective, our earnings in the first nine months of 2006 are slightly more than the earnings for all of 2004 and 2005 combined.

Lastly as you'll note from Jeff's discussion, our technical teams are doing really a terrific job of exploring our current low-risk development drilling inventory as well as developing and moving forward our emergent plays. Several of the emerging plays are showing initial results that are quiet exciting. Stepping back and looking at the big picture, we have a diversified portfolio of projects that's getting bigger day by day. And the unbooked reserve potential is now more than 3 times our crude reserves.

With that, I'll turn the call over to Roger to review the financial results.

Thanks, John.

The third quarter proved to be an excellent quarter with continued strong increases in production and slightly higher realized oil and gas prices from the third quarter of last year.

Year-over-year quarterly production was up 19% as our drilling program continues to provide steady organic growth, combined with a first full quarter of production by our new Stroud acquisition.

Our net income for the first 9 months of 2006 totaled $158 million; this is 42% higher than the net income posted for all 12 months of 2005. Despite the recent decline in oil and gas prices thanks to continued production growth and a strong hedge position, Range is on track to post another record year in 2006.

For the quarter, oil and gas revenues were $102.6 million, only slightly behind the all-time record first quarter 2006 figure of $176 million. Since year-end 2005, certain of our natural gas hedges are required to be mark-to-market at quarter end. This resulted in a non-cash, pre-tax gain of $55 million in the third quarter of '06 and a gain of $84 million year-to-date. No changes were made to the underlying hedges; the gain is solely attributable to the accounting treatment and change in commodity price. It may appear counter-intuitive that when prices fall, we post a gain, but because the mark-to-market accounting treatment went into effect at year-end when oil and gas prices were high and our hedge prices were comparatively low, gains are recorded as prices fall.

Looking at the cost figure for the third quarter, an explanation is required you can perform a meaningful comparison with prior quarters. Nearly all of our expense categories were impacted by reclassification of non-cash stock-based compensation expense pursuant to FAS123R; that's the new rule governing stock option expensing. So here's the full story; Range for many year has recorded non-cash stock compensation expense as the deferred compensation plan requires quarter mark-to-market expense based upon the ending stock price each quarter. A separate income statement line item was used to record this expense so that investors could separate this non-cash expense from other cash operating expenses. Investors have patiently listened to my explanation of these non-cash charges every quarter for almost 3 y ears now, and because our stock price decline $1.95 per share this year from the end of the second quarter to the end of this quarter, the deferred compensation plan mark-to-market expense for the third quarter of this year was actually a credit of $2.6 million.

The non-cash stock compensation expense line in prior years pertained exclusively to this deferred compensation plan mark-to-market expense. In 2006 we began including the non-cash equity compensation expense attributable to FAS123R in the non-cash stock expense line. We felt that this presentation made period-to-period comparisons easier for investors and that the cash versus non-cash nature of the expense merited the separation. Now, three-quarters into the new rule, a consensus industry practice has emerged with a non-cash FAS123R stock compensation expense is to flow through each separate income statement expense line rather than to a separate non-cash expense line.

Now, the accounting rationale here is to align the treatment of non-cash FAS123R compensation expense with the cash compensation expense. But because all full-time Range employees receive equity awards, not just senior management, the reclassification of this non-cash expense impacts every cost line on the income statement that contains employee compensation expense. Now the Form 10Q in our new release provides a breakdown of the reclassification to assist you in establishing comparability with prior quarters, but going forward there will be significant non-cash expense embedded in the various income statement expense line items.

Now, to assist you further, Rodney's investor relations group has posted on the home page of our website detailed schedules reflecting the year-to-date reclass for both '05 and '06. After adjusting for the non-cash expense reclassification, and John mentioned direct operating expense was $0.91 per mcfe in the third quarter, up $0.18 from last year's third quarter, and up $0.08 from the second quarter this year, increased costs in almost all production activities are responsible, but the largest increase is occurring in field service costs at $0.05 per mcfe, higher insurance premiums $0.04 per mcfe, and field personnel expense $0.03 per mcfe. Production taxes were flat for the third quarter of last year at $0.38 per mcfe.

As John also mentioned, there's some good news on the G&A expense front. G&A expense adjusted for the non-cash expense reclass was $0.31, level with last year and down $0.04 from the second quarter of this year. G&A expense is down primarily due to lower legal costs and lower franchise taxes. Looking forward to the fourth quarter, we expect cash direct operating costs to be in the $0.90 per mcfe range and G&A to be in the $0.35 per mcfe range.

Debt used to partially fund the Stroud acquisition, rising interest rates, and the refinancing of $100 million of our short-term floating rate bank debt to long-term fixed rate notes caused interest expense per mcfe for this quarter to increase $0.19 from last year. Of course, while debt is up on a quarter-to-quarter basis, our leverage as measured by the debt-to-cap ratio continues to decline.

Exploration expense, adjusted for the non-cash compensation expense reclass, was $15.8 million in the third quarter, compared to $7.2 million last year. A $4.9 million of the increase was due to higher dry oil cost and $3.1 million was from higher seismic expense. The 2 dry holes that were drilled were both wells where we experienced mechanical problems when some tools were left in the hole. But exploration expense in the $10 million to $12 million per quarter range is not unexpected given our current pace of activity. Exploration expense for the first 2 quarters of '06 unusually favorable to plan, due to a lack of dry-hole expense in the first half and an increase in seismic expenditures slated for the second half of the year. Pleas remember Range expenses all seismic costs, and of course the third quarter is often a heavy quarter for seismic expense due to favorable conditions.

DD&A expense increased by $0.27 per mcfe to $1.74 in the third quarter, up from $1.47 last year and up $0.25 from the second quarter of this year. The biggest story behind this increase is a $2.4 million impairment of a single offshore property that never fully recovered from the '05 hurricane. We went ahead and fully impaired this property at quarter-end, and this offshore impairment added $0.09 per mcfe to the third quarter DD&A rate. The remainder of the DD&A is ATTRIBUTED to the Stroud acquisition and changes in the production mix associated with our new drilling successes.

State income taxes required a $615,000 current tax expense in the third quarter of '06, but thanks to our $205 million NOL carry-forward, no federal income tax was paid in the third quarter.

Net income from continuing operations for the third quarter of '06 totaled $65.4 million or $0.46 per diluted share, once again, more than double the net income posted in the third quarter of last year. Net income from continuing operations per share for the quarter calculated comparably to the analysts' estimates was $0.23 per diluted share. This compares favorably to the consensus estimate of $0.22 per share. EBIDAX for the third quarter of '06 totaled $131.2 million, the second-highest quarterly EBIDAX figure in the Company's history. EBIDAX was 19% higher than last year's figure of $110 million.

Cash flow for the third quarter was $114.1 million, up 13% from third quarter of last year, and like EBIDAX, cash flow for the third quarter was the second-highest quarterly cash flow in the Company's history. Cash flow per share for the quarter was $0.80, the same as the second quarter, and as Rodney mentioned earlier in the call, please reference the full reconciliations of these non-GAAP financial measures are available on the Range resources website.

Looking further down the income statement, GAAP accounting requires that assets held for sale be revalued every quarter based on prices in effect at quarter -end. And though net cash flow from the assets held for sale was $8 million for the quarter, we recorded a total $30.4 million non-cash impairment, reflecting the drop in commodity prices and gas volume produced since the last quarter.

The impairment of assets held for sale, unlike an impairment taken on an asset used as continuing operation, may be reversed in future periods if oil and gas prices increase/

Turning to the first 9 months of '06, net income from continuing operations totals $171.8 million compared to $68.3 million in '05, a 151% increase. EBITDAX for year-to-date '06 totals $390.8 million, a 39% increase over the $280.8 million last year. Year-to-date cash flow in '06 is $351.1 million, 38% higher than the comparable $253.6 figure from '05. Cash flow per share year-to-date is $2.55.

Because the June '06 Stroud acquisition was captured by the second quarter balance sheet, there are no major changes to the third quarter balance sheet, other than refinancing $100 million of floating rate bank debt to long term 10-year fixed rate sub notes. The interest due on Range's debt is now 39% floating rate and 51% fixed rate, and the earliest subordinated note maturity occurs in 2013. While the switch to the long-term fixed-rate subordinated bonds from short-term floating rate bank debt increased our interest expense, the result is a more conservative and stable capital structure.

Our debt cap ratio at the end of the quarter was 44.5%, slightly below last quarter and below the year-end '05 figure of 46.9%. The progress we make toward reaching our 40% debt-to-cap ratio target will largely be driven by increases in retained earnings, the value of our oil and gas hedges, and proceeds from asset sales.

Our favorable hedge position does assure us the sufficient cash flow to continue our capital program without significant increases in leverage.

In the breaking news category, just yesterday we closed a new bank credit facility. This new facility includes 22 banks and it set our current available commitment at $800 million, up from $600 million in the old facility. This provides Range over $400 million in committed bank credit availability. A desirable feature of this new facility is that it established a borrowing base of $1.2 billion; that's derived from Range's current oil and gas property base. The $800 million commitment may be increased with bank approval to this $1.2 billion amount with 20 days notice should Range require additional borrowing capacity. The credit facility remains a 5-year revolving facility with a maturity date extended to October 25, 2011.

I had mentioned on the last call that early in the second quarter in anticipation of the Stroud acquisition and before gas prices fell, Range entered into gas hedges carrying much of our remaining '06 gas volume, as well as additional volume in '07 and '08. We added 2006 natural gas collars on $30 million per day with a floor price of 708 and a cap of 883. Gas swaps totaling $75 million per day were added in '07 at a price of 959 and $105 million per day of '08 gas swaps were added at a price of 942. Range has always hedged a significant portion of its near-term production volume to provide a predictable level of cash flow for re-investment and with the hedge position that Range currently holds, significant cash flow certainty exists for the remainder of '06 and into '07 and '08 which will allow us to orderly exploit our drilling inventory and expand our emerging play.

Those wishing to update t heir financial models can find a detailed summary of our hedge position on the home page of Range Resources website.

In summary, while the reclassification of non-stock compensation expense produced some accounting static on the income statement, our third quarter of 2006 cash margin was a very healthy 429 per mcfe. And with all the sector concern about falling low on gas prices, it's easy to overlook but important to remember that our third quarter financial performance produced the second highest quarterly oil and gas revenue, EBIDAX, and cash flow in the Company's history. The 19% year-over-year production volume growth, our 15th consecutive quarter of production carried the day.

John will now -- I'll turn the call back over to you.

Thanks Roger, excellent update. Now I'll now turn the call over to Jeff Ventura, our Chief Operating Officer to review the exploration and development activities. Jeff?

Thanks, John. I'll begin by reviewing production.

For the third quarter, production averaged 289 million per day, a 19% increase over the third quarter of 2005 and a 10% increase over the second quarter of 2006. This represents the highest quarterly production rate in the Company's history and the 15th consecutive quarter of sequential production growth. For all of 2006 we're predicting 15% production growth. We're also predicting 15% production growth for 2007 and I feel good about our ability to achieve that.

I'll now review some of key projects, and I'll start by looking back at our acquisition of Pine Mountain, which occurred in December 2004. Production has grown from approximately 14 million per day to about 25 million per day. This is about 50% higher than what we originally projected. This has been a great project for us; funding costs for new wells are typically less than $1 per mcf, which is outstanding and amongst the best in the industry. As good as the properties have been, I believe the future will be even better. We've identified a half a tcf of low-risk unbooked upside in the Nora Haysi area, and with successful [bound spacing] it could be double that. To put it in perspective Range's total crude reserves are about 1.6 tcf.

Another very impactful low-risk project is our Barnett Shale position in the Fort Worth Basin. We had built a position of about 18,000 acres prior to acquiring Stroud this past June. When we acquired Stroud, we doubled our acreage position to 38,000 acres and picked up about 16 million cfe per day along with a great team of Barnett experts. Today our Barnett Shale production has almost doubled to approximately 30 million per day, and our acreage position has increased to 49,000 acres. Importantly almost all of our acreage is in the core or expanding core part of the field. We believe that this position represents about a tcf net to Range. Importantly, we have a super team in place to continue to build value for our shareholders.

The third project for higher risk represents the opportunity to more than double the Company by itself. That's our Devonian Shelf Play in the Appalachian basin. It represents more than 2.5 tcf of upside and currently we have more than 314,000 acres in the play. By year-end, we'd like to be at 400,000 acres and I'm confident we'll get there. We started sell gas from our first vertical well in December of last year, and shortly thereafter added 2 more vertical wells to sales. They are performing well, and based on reservoir simulation appear to have reserves between 600 million to a bcf per well. Recently we just brought on line 3 new vertical wells. They have peak rate of 522 mcf per day, 888 mcf per day, and 1.4 million cf per day. Now to put that in perspective, a well that IPs for 1.4 million per day could be over a bcf.

Within a week, 2 more vertical wells will come on line and by year-end we've have 10 vertical and 3 horizontal wells on line. We estimate that in development mode, we can reduce the cost of a vertical well from $1 million to $1.2 million per well to $900,000 per well. So assuming the mid-point of the reserve range, which is 800 mcf per well and $900,000 for a well, our finding and development costs would be about $1.30. At a $5 mcf per NIMEX price, this equates to a 32% rate of return. AT strip pricing, it increases to a 48% rate of return.

It's interesting to note that in the Barnett Shale, Fayetteville Shale, and the Woodford Shale the early vertical wells were either marginally economic or uneconomic. I'm encouraged that we're starting off on our Devonian Shale program with such good results. It's also important to note that in the areas we've identified, there have been approximately 400 wells drilled to date, to or through the Shale historically. Based on historical data, we have confidence that the acreage we're acquiring is in the gas window, has good shale thickness, has good gas in place, and is at a reasonable depth. What we're doing in applying state of the art technology in a good gas price environment to unlock a huge gas resource. In 2007 we plan to expand the Shale development program to 60 vertical wells and 4 horizontal wells.

I've talked about 3 plays with huge upsides; now I'll switch and talk about how a talented technical team helped with state of the art technology in a good oil and gas price environment can impact old fields. We won the oil and gas investor award for the best field rejuvenation based on the results of our Westfirm and Moscow unit. That's a field that was discovered in the 1930s and the unit was operated by one major and 2 independents before Range acquired it. Since we began redeveloping it we've increased production from less than 300 barrels per day to about 3,000 barrels per day. That performance speaks to the quality of the people we have at Range. Most of the increase was from down-spacing to 10 acres coupled with some refracing. We're currently testing 5 acre down-spacing with water flooding and it looks very encouraging.

Another example is our [Unis] field, and we acquired those properties in June of 2005 and at that time, they were producing about 7 million per day. Since then, we've driven up production to more than 21 million cfe per day. That's well ahead of schedule and more importantly the finding that development costs are below $1 and our LOE is about $0.50 per mcfe, an outstanding job by the team.

The third example is our Tonkawaw project in Northern Oklahoma. This field was discovered about 1920 and essentially abandoned in the 1930s. During its peak, it was the largest producing oil field in the United States. Our guys again have done a great job of redeveloping it and production has risen from essentially zero to about 1,000 barrels equivalent per day. We now have identified more than 400 new drilling locations, again outstanding team work.

In addition to these old fields, we also have some exciting new exploration plays. We currently have 4 deep wells in Southern Oklahoma. The first well, in which we have a 16% working interest was completed in the spring and should be on line by the end of the months. The second well we operate and have a 70% working interest in. We just logged it and ran pipe, and will be completing it in the Springer.

The third well, with the Springer as a primary target, is drilling ahead and should be a TD by year end. We operate and have a 44% working interest in that well. A fourth well just spud and has objectives in Marrow and Springer. We operate and have an 82% working interest in that well. Each of these wells has the potential to come on line at rates in excess of 10 million per day.

We're also 4 along on our high-risk, high-potential Norfolk well. It should be at TD, which is about 22,000 feet in December. We have a 25% interest in the well. In a successful full-field development, this could add 150 million per day net to Range.

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 approved reserve base of 1.6 tcfb; on top of we've identified more than 5.9 tcfb of up0side, primarily in low-risk, coal bed methane shale gas and [tight gas sand] plays. We have a great track record of converting that to value for our shareholders. We have 15 consecutive quarters of production growth, and I believe no other company in our peer group can say that.

Also according to the Bank of America study of their high-yield group, which includes companies like XTO, Quick Silver, Chesapeake, Danbury, and Newfield for a total of 18 companies, Range has the lowest all-end unit cost for the last 2 years. The unit costs include F&D, LOE, G&A, and interest expense. 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're in a terrific position to continue to build shareholder value on in to the future.

Back to you John.

Thanks Jeff; terrific update. Now let's look to the remainder of '06. Obviously, we're hoping and we're focused on continuing strong operating and financial results fourth quarter '06 like the prior 3 quarters will, in our opinion, be important and they'll continue to demonstrate our solid quarter-to-quarter execution of our strategy. And as we stated, it all starts with production.

We're looking for fourth quarter production volumes to be approximately 292 to 294 million cubic feet a day representing a 17% increase year-over-year, and we'll also set another record high for the Company. If we achieve this, it'll result in a year-over-year increase of 15.3% for 2006, which slightly exceeds our target that we set at the beginning of the year of 15%, so we're very pleased with that as well.

On the price side, if you look at yesterday's futures prices and the hedges we have in place, we anticipate fourth quarter price realization after hedging to be in the $6.40 to $6.50 per mcfe range. This is lower than the $6.81 per mcfe we realized fourth quarter of 2005. However, with the 17% projected ramp-up in production, this should more than offset the drop in realized prices. As a result, we expect fourth quarter oil and gas revenues to increase by over 10% year-over-year.

For the year, we're looking for cash flow from operations to increase about 40% over 2005. So as you can see, 2006 really shapes up to be a tremendous year.

Looking a little further ahead, as Jeff said we anticipate production to continue to increase in 2007, a result of our positive drilling result so far this year and our large inventory of over 8,000 drilling projects. We have again set our production target for 2007 at 15%.

When you really think about our business in the way we think about it here at Range is that we believe that shareholder values determined day-by-day by the degree of success, that we generate attractive returns and wise use of capital. The efforts and quality of our technical team are critical in this process. At Range, we've built what we believe to be one of the highest quality technical teams in our peer group, and they really generate a lot of really neat opportunities as Jeff mentioned.

Today as we keep on saying over and over again, we've got a very large inventory of low-risk development projects, but we also have a diversified group of higher risk, higher potential exploration projects as well. We believe that we're unique in that for our size we have a very large transparent drilling inventory and a leasehold position that now exceeds over 3 million acres. We've worked very hard at building to maintain our top quartile cost structure and expand our drilling inventory to drive long-term growth and profitability.

One of the keys we believe is keeping our eye on the ball in terms of cost. Both Jeff, Roger, and I approve all expenditures over $200,000. We are focused on making sure we spend capital wisely. Expenditures are only approved if they meet a hurdle rate of return based on our AFE price deck which is currently $6.50 gas for the remainder of 2006, $6.00 gas for 2007, and $5.00 gas for 2008 and beyond. We think that's really important and that's where we allocate capital on that basis.

Thinking ahead a little bit, we've recently h ad a lot of questions from shareholders and investors regarding our capital plans for 2007. As I mentioned previously, we have set an aggressive 15% production growth target for 2007. The good news is that we believe that we can achieve this target based on our capital budget that is roughly equal to our estimated to our 2007 cash flow. So we don't anticipate increasing our leverage to achieve our growth goals in 2007. This is really the primary reason we hedged roughly 70% of our 2007 and 2008 gas production at a floor price of $8.50 per mcf so that we have confidence in continuing our growth strategy without damaging the balance sheet even if we experience a dip in prices.

Besides exploring our large inventory of low-risk development opportunities to drive baseline growth, we are keenly focused on continuing to move forward our emerging plays. A fair amount of our 2007 capital expenditure will be used to continue this process. For example, as Jeff mentioned, we plan to drill over 60 shale wells in our Appalachian Shale play; this compares to 13 wells in 2006.

All in all, we believe Range is in an excellent position to add significant per-share value in 2007 and beyond. As I have said many times before, our focus at Range is not increasing our market capitalization, but it's to increase our stock price. And when you look at Range, there are really 4 main points; first, we've achieved peer-leading consistency with our growth plan, 15 consecutive quarters; second, we have a large multi-year inventory of low-risk drilling projects that will continue to drive our baseline growth; third, our '07/'08 hedges essentially assure us of reporting very attractive financial results and allows us to continue our growth strategy regardless of short-term price fluctuations; and lastly, we have a number of emerging plays that in the aggregate have over 5 tcf of reserve potential that if successful will significantly impact the valuation of our stock.

With that, I'll turn the call over the Charlie to get his thoughts. Charlie?

There's really not much of anything I can add that no one has said except to point out that the results speak for themselves, and I couldn't be more pleased with the efforts of the entire organization. I'd like to express my sincere [inaudible].

Thanks Charlie, and Charlie really does a terrific job having somebody with 40 years experience at Shell and running Shell North America really is an asset that a Company like ours is, it's really a tremendous asset. Charlie has really been a big pat of the Range story.

With that, operator why don't we turn the call over to questions and answers.

[OPERATOR INSTRUCTIONS].

Rahan Rashid, Friedman, Billings.

Jeff on the Pennsylvania Shale, did you mentioned that you have 400 penetrations throughout the acreage and that you have core samplings from those?

Yes well, that's an important point in that when we talk about the big acreage position that we have obviously by year-end like we said, we'll have 10 wells, 10 vertical and 3 horizontal wells tested, but there's some concern over that whole acreage position, well over 300,000 acres. But the reason we have confidence that acreage if very attractive is because of all those old penetrations; they were drilled for other horizons, they give you data on the shale thickness and shale properties so we're confident again in the gas window, it has good gas in place, it's at a reasonable depth. It has all the things you'd look for, so even though we haven't spotted wells on that other acreage yet, and I'm excited about it, and we will like John, like both John and I said, we're going to really expand our program and be testing across that whole acreage position throughout 2007.

Interesting, interesting; the Nora Haysi down-spacing, if down-spacing what would qualify as a success and roughly what timeframe milestones are we talking about?

Well of course, the timeframe we've already started drilling the wells and we're in the process of drilling the wells and we'll be completing the wells then it's just a matter of how fast they respond. But the good news they're basically in areas that are already de-watered that have produced very well. They've had reserves for wells, over 400 million cubic feet of wells from depths of 2,500 feet. Again, that's where we're getting the low finding cost of $1.

So if we see reserves that meet our economic criteria generate good -- we'll be looking at the same thing, do they generate good rates of return. Again, we pressure test all of our projects; we don't drill wells unless at a flat $5 NIMEX they have rates of return in excess of 20%, and when you flip in strip pricing then most of the rates we turn in are 40 -- over 100%.

So we'll be looking at these same economic parameters; do they have good rates of return; do they have good finding costs; and then timing wise we'll have the wells drilled by the end of the year and completed early next year, and then it's just a matter of how quick they respond.

The good news again, to put it in perspective our reserve is currently on the order of 1.6 tcf unbooked upside based on current 60 acre spacings, a-half tcf that could double. So we could be looking at a tcf of upside to 1.6 tcf of company in an area where we have great rates of return, great finding costs. So that's why we're so excited about that particular project.

Got it, and do you think will you need a couple more pilots before you start doubling your number of locations, or because of the core sampling --?

Yes, I'm going to feel pretty good; I mean if these 20 wells work, I'm going to feel pretty confident that you can really apply that across the field, in which case will prove up a lot of reserves because then you're going to have literally a one-well [offset]. We'll be ramping, we're in the process of putting together our budget for next year; we'll be significantly ramping up our CBM drilling there regardless.

And again, remember that we're testing going from 60 acres to 30 acres per well; [Console] already has successfully going from 80 to 40, so we know 40 acre works on the other side of the field. So it's a good project and we're looking forward to the results.

And topography all across the acreage will lend itself to essentially doubling the number of locations, or there could be some issues there?

I mean, those wells are scattered across that whole position, so we'd be in-filling within areas we've already developed. So I don't think that'll be an issue. Granted there'll be some [air] but generally speaking I don't think that's an issue.

Two more quick questions; on the Oklahoma front, Marrow/Springer, do I remember correctly that have maybe 20-plus locations? And if you do and if some number of wells are to be drilled before year-end are successful, does that de-risk the whole 20-plus locations? Could you elaborate on that please?

We have actually I think in a success case, we'd have significantly more locations than that. And I do believe that if these 4 wells are good and based on a couple of other wells that Marathon has drilled on the structure coupled with ours, I think it would de-risk it, so at that point it would be a development-type project. So it's very exciting; it has the potential I think on the rate side net to us to be over 100 million a day in full development so it's going to be throughout 2007 and 2008 can really continue to drive up our production rates.

One last question; on the Pennsylvania Shale, you gave a peak rate for those 3, 4 wells from 522 to 1.4; could you walk us through why maybe that wide variation and then I'll yield the floor. Thanks.

Frankly people talk about that all the time and whether it's the Barnett Shale play or other place, and my background as you know is petroleum engineering and I've looked at fields in the U.S. and all over the world, and that's what I've done my whole career; every oil field in the world is [log] normally distributed so that's really a normal distribution that you would see anywhere.

I think the important point is if you look at the first 3 wells and it looks like if you take the mid-point of the range, 800 million a well it costs you $900,000 maybe to get 800 million cubic feet of reserves, which would be in the $5 case, 48%, or 32% rate or return and at strip pricing 48, they have great finding cost of $1.30; but 2 out of the 3 wells that I mentioned for then new wells had higher initial rates than the first 3. So form an engineering perspective typically higher initial rate leads to higher reserves. So I'd be thrilled if the mid-point of a vertical well was 800 million. But although it's extremely early, typically higher rates may mean higher reserves because 800 million moved to 900 million, or like I said on the high end of 1.4 million a day well may be over a bcf, in which case the rates of return would be higher, finding costs would be lower.

But it's early on and it's unique to some of the other plays that we're getting some encouraging results so soon. And again, we're really in an industry-leading position, well over 300,000 acres; by year-end, we will have 400,000 acres in that play and the reserve upside won't be 2.5 tcf; obviously, it'll be a lot higher number than that.

Again, to put it in perspective, our whole Company reserves right now are 1.6 and you talked about, we've talked about a lot of plays; really any one of them could significantly impact the Company, the fact that there's a lot of ways to win at Range in a big portfolio of quality projects being executed by quality people.

Thank you.

Tom Gardner, Simmons & Company.

Good afternoon guys; Tom Gardner. I have a couple of operational-related questions concerning the deep tight gas opportunities mentioned in your ops report on the Widen acreage, is that a tight sand or shale, or both?

In Widen?

Yes.

Well in Widen we're looking at, I mean there you have the field originally that's been developed is on the order of 3,000 to 4,000 feet and it's a combination of limestones and sandstones and they're good wells and we have big acreage position there, close to 80,000 acres where we have 100% working interest and 100% NOI.

And then on top of that you have a couple other things to consider; one on the shallow end is coal bed methane; it's about 1,800 feet; we have basically a 10-well pilot. Some time hopefully around the middle of next year we'll see how the water is going. If it works, that could be 200 tcf of upside at about $1.30, good rates of return.

The other big upside, and we haven't talked much about it, but it's pretty exciting is the shale potential below that, now which would be Devonian shale; you might have seen today in fact, Equitable released the results of good shale well in the basin from a horizontal well I believe, although it's speculative and early, but it was within Equitable's release I believe today, they're using the Packers-plus like cabinet. Murray Gerber said it could change the Basin. We have that kind of potential on our acreage at Widen; we'll be trying a couple of shale wells this year and next year, and also in some of our other positions there.

Really all up-talk about with 300,000 acres is the northern pat of the basin, so there's a lot of exciting things throughout the basin in multiple levels. That's really why we like it; you've got potentially productive horizons from 1,000 double weight to 10,000 to 12,000 to 15,000 feet. So it's a good stack-pay area; you get a premium to NIMEX to $0.35; we've got one of the biggest acreage positions in the basin and we'll be exposed to all that potential and all that upside.

It's a long answer; hopefully I answered your question in there.

It's a great story.

Jumping over to the Barnett, your recently-acquired 4,000 acres, where is that and is it more of kind of an infield opportunity by expanding core, non-core?

The acreage that we've been adding to it predominantly has all been in the core, expanding core and we're adding in and around where we are. We've talked about -- I can get into the specific things if we had a map in front of us -- but it's in the areas we've had good success in and it's sort of tack-on to our existing positions.

Again, I think just a great performance by the team to take that form 16 million per day to today we're over 30 million per day in a short period of time, and we think that production will just continue to climb there.

When you look at that play relative to other plays in the country, it's one of the most, has some of the most robust economics, and there's been different studies out by AG Edwards, by Pickering, by your company and when you typically look at the Barnett versus a dozen plays across the country, strong rates of return. So we've got a great acreage position, tcf of growth for Range with just I think if not the best team in the Barnett Shale, certainly one of the best teams out there.

Great, great, and just one point of clarification on that Pennsylvania Devonian; all those wells were completed with the same technique, no variation there, it's pure reservoir distribution on the reserve side, or initial rate side, log normal distribution?

No we are actually experimenting with different completion techniques so they've all been, the wells I've talked about, they've all been vertical wells, but how we're completing them and how we're fracing we're like in every play, particularly in the resource plays, but even in conventional plays you learn as you go. So I think our team is getting smarter about how to increase rates and in crease reserves as well as how to drive down costs. So we're still in that mode and we'll be in that mode even through next year. But if you look at any of the plays typically through time, reserves have gotten better, costs have come down, and I think that we're on that same trajectory but it's early.

Excellent, thanks guys; great quarter.

Andy O'Connor, Wells Capital Management.

Thank you, good afternoon, congratulations on your quarter. I wanted to know, I think the total net acres for shale gas projects increased from 314,000 in last week's production report to more than 400,000 by today's announcement. Can you break out where the 400,000 acres are located?

Andy this is John; I think it's just a matter of semantics; the 314,000 acres relates just to the Devonian Shale play in Appalachia. In the Barnett, we've got about 49,000 acres; in the Permian Basin out in West Texas we've got about 20,000; then we've got about something close to 30,000 or 40,000 acres in the Woodford in the shale place in Oklahoma and out east of us.

So when you add all those up, you get to 400,000. And just to clarify, when Jeff says he wants to get, we want to get to 400,000 that relates just to the Appalachia; we sat down with our shale team down there and looked at success and so we've really given them some more dough to pick up some more acreage up there, so we're looking to taking that 314,000 to hopefully, we told them that we want to get to 400,000 by the end of the year, obviously on the same terms, less than $50 an acre and 5-year leases. And again, that's one of the nice things about the Appalachia play is you've got cheap acreage, long terms on the period of time, and you've got in most cases an [age] royalty. So it's one of the reasons why we like the play besides the fact that we're up there, we've got a big team, we've been there for 30 years, blah, blah, blah.

So hopefully that clarifies this, the numbers on the acreage.

I appreciate it, so maybe another increment of 100,000 between now and year-end?

Yes I guess; technically about 86,000 but --.

But we'll probably be adding to some of those other areas. Our position in Fort Worth Barnett will continue to grow and will continue to grow in the [Floyd] so we'll be adding to those 3 for sure.

Thanks for that; and then secondly I may have missed this, was there a capital expenditure estimate for '07?

Andy what I said is I think what we're looking at right now if you just take the -- and this is not with a microscope because we're still all the teams are submitting all their capital requests -- quite frankly if we left it to them, they'd probably spend 2 times our cash flow, but I think Jeff and I have spent some time and really thought about this and we really think the appropriate thing and we're going to get terrific growth anyway, but we ought to be somewhere plus or minus 5% or so, maybe 10% plus or minus of our cash flow in terms of the capital budget. So I've seen projections for our cash flow all over the place, but just to give you a rough idea, I think around $700 million is probably plus or minus the number I think at the end of the day we'll come up with, but that's still really early, we're still getting all that submitted, and obviously, there's 7 members of the Board of Directors, Jeff and I and Charlie and 4 others so they all have to approve it as well.

But I think that's kind of where we are, and I think we've typically tried to be fairly disciplined on the capital side; obviously if we see opportunities that are exceptional, we'll willing to spend more than our cash flow, but they really need to be exceptional because we want to keep the balance sheet in shape, and as Roger mentioned, we're continuing to whittle down towards the 40% debt-to-cap target that we've been working on here, and we just don't want to jeopardize that. And there's always that balance between growth and discipline and balance sheet security so that's the thing you struggle with.

Again, I think the good news at Range is that obviously one of the big factors here is commodity prices and at least for '07 and '08 we've taken a lot of that risk out of our business model by those $9-plus hedges that Roger mentioned in his talk. So that's one of the reasons that we feel pretty good about announcing our growth target so early on '07 and being pretty comfortable with that.

Thanks for that; would successful down-space drilling at Nora to 30 acres, would that change the '07 Cap-Ex appreciably?

No really; I mean you're going to see good growth in the number of wells drilled but we have so many locations, even on 60-acre spacing we've still got in excess of 2,500 locations to drill. So we've got a huge inventory and we'll be ramping up, but it will not change the number of wells we drill; what it will change is the confidence we have in that tcf of upside could be there.

Sure Jeff would you have to add more rigs then, or would you plan to add more rigs again if you're successful with down-spacing in Nora?

Yes, we're going to be ramping up I think regardless, but in the future you would be. The other good news there is remember that one rig could just drill about 2 wells a week or about 100 wells a year, so to really ramp up, you don't have to add many rigs to get a significant more number of wells versus say a 15,000 foot Bosier play in East Texas or something where the wells take 180 days per well for one rig. So you really can get a lot of the economy per scale quick.

Thanks Jeff, thanks John.

Jack Aiden, Key Bank.

Hi guys; I've got a few question. On the DD&A I guess you had $0.09 more or less on the current guidance. Is it fair to say that quarter-to-quarter DD&A is somewhere around $1.65?

Yes that's a good number?

Okay, second question is Jeff on the Trenton Black River and Norfolk could you handicap a little bit those 2 areas for us going forward?

Well the -- I'll start with the Norfolk, again we show the reserve pyramid and it ranks things from low risk to high risk, the Norfolk being the highest risk well really that we're drilling, or that we'll drill this year. And again, to put it in perspective net to us in full development could be 150 million a day and remembering that our third quarter volumes are 289 so it could be a lot of reserve growth. We're still drilling the well, it could be a TD by year-end, but so far it's too early. All I can say is the drilling so far has gone well.

In terms of Trenton Black River in our press release we did say that we ran pipe on the well; there's multiple intervals to test and we'll begin that in the fourth quarter, and I really can't say more than that. Again, Talisman is the operator; we're 50/50 in that well.

Okay, the next question are you ready to drill a big -- I guess supposed to drill a big well important well in the Stroud acquisition. Is that done or are you doing some more work there?

I think probably what you're referring to, the Stroud acquisition a lot of that really is a lot of low-risk development in proven areas. You're probably referring to the Ellis County stuff that we had prior to that which in some cases we refer to as the undercover Barnett well. We did acquire our 3D, the data from the 3D; the quality of the data looks good. It's in processing right now; we'll be interpreting it and we hope to spud a well right at the end of the year, and of course it'll be drilled on in the next year and then tested but we've got a great acreage position there; it's a great concept. We feel confident we'll get a big thick Barnett section, but we need to drill it and test it and get it on line and prove to people what it is. But that's on track to spud by the end of the year.

Okay, the next question is that how are you doing with the assets of the Chalk Property, the Austin Chalk Property?

Jack this is John; we, in retrospect we put the Chalk Property up for sale at exactly the wrong time. It was right when gas prices started to tank. So where we are is that we've kind of slowed the process down; there's still some people looking at it, and we still hope to sell it. But I really believe what needs to take place, which is I think we're starting to see the early signs of it is some confidence where some of the '07 gas prices are going to come out before we get what I think is a reasonable offer for it. The Chalk Properties just due to the nature of the short-term next 12-month gas price has a huge impact in terms of valuation so the bad new is I don't think we put it on the market right at the wrong time, not much we could do about it. The good news though is that we drilled, we continue to develop the property; we've drilled 2 terrific wells and none of this production or what-not is in our production numbers, but we drilled 2 really terrific wells so there's more PDP production than there was before. It also helps prove up some of it, and then you obviously over the past couple of weeks have seen some strengthening in gas prices from the what looked to be continuous nose-dive. So I think once all those things settle out, then we'll kind of repackage it again. Again, there's several people looking at it but I think to get a number that we're going to be comfortable with I think it's going to take a little time and patience is going to be the key. We certainly don't want to sell it at what we think is a silly price; we want to get a fair value for our shareholders.

I don't blame you; now the final question is that we've been hearing that some people that got into the Floyd Shale and drilled somewhere are very disappointed and there is some acreage available, one of the operators doesn't want to operate. Are you hearing the same thing?

What I would say is the Floyd Shale play, one it goes across a huge area, so the depth that you find the shale and the thicknesses and all really vary. And it's very early on in drilling. And so I think it's just too early; I'm really excited; I was down in Houston yesterday; went through our position again with our guys. There's some very quality, EOG is currently drilling there; they're in the process really I think they're drilling their first well; obviously EOG has a great shale team that know what they're doing. Chesapeake just bought into the play; they've got a good shale team. I think it depends though on where you are in terms of the quality.

But it's early on; I'm excited about our position; we're going to continue to add acreage; we're adding acreage for inexpensive, low cost per acre and most of our leases are 5-year leases with 5-year kickers so we're tying acreage up for 10 years with not a lot of money. I think it has a lot, it really has all of the characteristics you need to make a successful shale play. The one that you really don't know is the actual rock properties itself, and until enough people drill wells and test them, we won't get that piece, but we've got a first class shale team here at Range and our guys like the opportunity and we're going to continue top accumulate acreage and then we'll share on our compadres there at EOG and Chesapeake to the extent that they have a success that I think will speak well for our acreage and I think we'll probably drill our first well some time in the first half of next year.

What is your acreage?

We're not saying that because we're still in the process of accumulating acreage and putting it together.

I see.

But it makes a big difference where you are. I'll say a couple of things; one it makes a big difference where your acreage is and it also makes a big difference who your shale team is. And it makes a difference at different times as you go throughout the plays form early on to a year or 2 years into it how people perceive that play.

Just to kind of expound on what Jeff said Jack, I think the one thing that I've learned out of this is that all these shale plays are very different and that if you look at the Barnett play and then you look at the Appalachia play which are the 2 that we have the most history on, they couldn't be more different in some respects. The Appalachia play you have lower initial rates, but much shallower decline; it's much shallower than the Barnett in Fort Worth. Our vertical wells look pretty good starting out; the Barnett wells when they started first vertical wells looked pretty crummy. I mean, and there's a lot of different things on just how to complete them and produce them that is really different. And I think there was a question on are we completing them differently, one of the questions asked before, and in the district where Jeff is we try, I think we've drilled 10 or 12 wells; I think we've tried 6 or 7 or 8 different kinds of completion.

So there's a lot of testing a lot of different things going on, but like Jeff said, it all really comes down to the people you've got doing it and their abilities to unlock the code. And the key is to have that good team and put them in place and letting them operate. And that's really the really we got into Barnett so late is because we didn't have a team. We finally have a team there and we're making good wells and we're trying to use some of that expertise to go to these other areas.

But other areas are going to be different; it's going to take time just listening to Newfield talk about some of the things they did you could tell how long the Woodford took and some of the things they're challenged with the same things with Southwestern, with Fayetteville. There's always bumps in the road and you start over time, you figure it out and then you can get more repeatable as you figure it all out, and it just takes time. And I'm as impatient as anybody on the planet given I'm the largest single shareholder of the Company, but I think our team is doing a really good job and they're doing it with a great disciplined approach. And it's pretty exciting, so we'll see.

Thank you very much.

We are nearing the end of our conference; we will go to Ron Mills of Johnson Rice for our final question.

Good afternoon; I'm not sure if there's much left to ask but just in terms of completion in the Barnett, you've had a couple of companies come out and talk about lack of pressure pumping capacity. One, in the Barnett do you have any of those issues facing you, and b), there's also been talk of water restrictions in some of these plays. How are y'all in terms of water capacity and pressure pumping?

We're actually in a great position, and again like John said when you circle back, it comes back to the people. Mark Whitley and his team are, have more experience lignin up that type of stuff and planning logistics and knowing how to operate, they've been there and done it really longer than any other team.

Also right now we're running 5 rigs so we aren't stressing the system with 15 or 20 rigs. So in terms of Range, well we have some of our own water wells and access to water; we've got our frac crews lined up, rigs lined up; we're in a great position.

But you're right, there are some companies that are having some problems like that.

And from a completion standpoint, you're about 30 million a day in the Barnett right now; what's your frac schedule look like? Do you have a slug of wells set to come on in the coming weeks, and how should we try to look at your Barnett growth profile?

We're just going to I think try to keep people focused on the portfolio. We've really ramped up production significantly from 16 million in May to over 30 million today, and I think we're going to continue to ramp it up. I mean to try to give you some help, we're going to stay at 5 rigs through the end of this year; early next year we'll pick up the 6; like John said, we're working on budget and we may end up next year at 8. But I think we'll get good solid growth for years to come out there. We're in a great position; great acreage, great team, and we've got services and rigs and everything that we need.

And then finally just as you look at West Texas, we talked about Floyd, the Devonian Shale, the Barnett, just like the Floyd some mixed results on some of the shales out in West Texas; what y'alls approach going to be on your West Texas shale acreage?

So far I really like our approach. Our strategy originally we got into it because off of some old [cootie] lines we had identified some [wood firred] structures and some interesting [wolf camp] things. Then the Barnett concept sort of evolved in there. Early on we picked up acreage for not a lot of money, with good nets and long-term leases. Our strategy was to go slow, let other people go up the learning curve because of Barnett and out there is deeper, it could be different, and lo and behold that's what it was. And at the same time while we're watching them go ahead and acquire the 3D over our 2D [Fussleman] lease.

We did that; we shot our 3D this summer; we just got it back in August, and the good news is -- I'm really excited -- our Fussleman structure shot out; they looked great. We've got some nice Fussleman structure; some of them over 1,100 acres, 350, 400 feet of closure. Typically those things work and they're nice wells.

So now we can target and we'll drill our first well, probably spud it some time in the first quarter of next year. Again, we're putting together our budget, but we'll target our first well right on top of one of the Fussleman structures which I feel really good about, and as you drill that then you're going to drill through the wolf camp, the Barnett, through the wood firred and into the Fussleman, so we will test multiple horizons with our first well and see where we go, but if nothing else works the Fussleman looks great; there's some good wolf camp production out there and I hope for the industry the Barnett does work so we'll have great exposure to it.

And then with your vast acreage exposure in these plays in your current activity levels, and even what you think you may do in '07 any lease expiration issues in any of the plays that we should start to worry about?

No we're in good shape there too. We plan for that, we know what it is, there's really nothing pressing or any issue that I see. And a lot of the leases that we have really are long term. So I feel good about that and our ability to drill it and hold it.

And then clarification, the 20% or 25% return on the 8,000 projects that you have in your exploitation inventory, did you say that was based on a $6 price in '07 and a $5 price in '08?

What we do Ron is we run strip pricing but then we also pressure test it on the downside, and the pressure test cases in essence are it's a $5 flat long term, and then we look at basically at $6 in '07 and then $5 flat forever NIMEX, and then the oil price one is basically $40 flat forever. So under that lower price scenario we look to see that we have a 20% rate of return or better; granted some of them may be high teens of mid-teens, and then we rerun them at strip pricing, typically any -- and on the low price case, they'll range from 15% to 40%, 45% when you flip in strip pricing that'll change from 40% to over 100% rate of return. So we pressure test our wells for rate of return; we also look at finding cost; do they have decent rates of returns; are they good finding costs; are they in areas that we know well where we have good teams. And if they meet those criteria, we'll drill them and if not, we won't.

All right, thank you guys.

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

Thank you operator; well I want to thank everybody for joining us today. We're excited about where we are in our position; I think tactically we've been disciplined, we've executed our plan, we've delivered, and that's really the key I think is just continuing quarter-to-quarter delivery and being focused and not letting these costs get away from us. And I think that's where we are and I think again, it all comes down to the technical teams and the operating teams and I want to applaud them as well as Roger and his accounting team for putting up with all the new what I consider fairly foolish accounting rules, but we won't talk about those any more.

But again, thank you very much and we'll see you next quarter; thank you.

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