山脈資源 (RRC) 2005 Q4 法說會逐字稿

Welcome to the Range Resources 2005 financial results conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question-and-answer period. At that 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 again reported record results for calendar year 2005, and for the fourth quarter of 2005, with a 22% increase in production, and a 37% increase in realized prices over the prior year. More importantly, the 2005 capital program was successful in both its all-in $1.46 finding and development cost, but also its 365% reserve replacement for the year.

We're pleased to discuss our results with you today. On the call today with me are John Pinkerton, President, 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'd like to cover a few administrative items. First we did file our 10(K) with the SEC this morning. Now available on the home page of our website, or you can access it through the SEC's Edgar system. In addition we have 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 reconciliations of our non-GAAP earnings to reported earnings that are discussed on the call today. We've also posted on the website our calculation of finding and development costs and reserve replacement, which will also reconcile such calculations with the guidance from the SEC Division of Corporate Finance. Tables are also posted on the website that will give you detailed information of our current hedge position by quarter. Second, Range will be holding two analyst day events next week. The first will be in New York City on February 28th, and March 1st in Boston. You can still register for the events on our website. For those of you who are unable to attend in person, there will be a webcast of the event. Please check with the website. Since we'll be presenting some proprietary maps and data, those materials can only be seen at each presentation and will not be included in the webcast slides. Therefore, I'd urge you to attend if at all possible. We will also be attending the Simmons & Company Energy Conference in Las Vegas on Thursday, March the 2nd, next week.

Now let me turn over the call to John.

Thanks, Rodney.

We had a terrific 2005, and what I'll do is before Roger reviews the financial results for the year, I'll discuss a few of the key accomplishments. As Rodney mentioned, we had very good production results for the year. Our fourth quarter production rose 16.5%, and we had a 22% increase year-over-year. On the drilling program, we continue to generate very attractive rates of return; and we continue to be very pleased with the drilling results that we're seeing out of our drilling. At year end, our approved reserves totaled 1.4 Tcf -- Tcfe. This is a 20% increase over 2004. And I think more importantly, the reserve growth was accomplished at a finding cost at $1.46 per mcf, which is in our view very good. Based on what we've seen to date, the $1.46 looks to be in the top 10% of our peer group, and when you look at our drill bit only cost, it was $1.16 per mcfe, so we're very excited about that as well. We would -- we combine the 22% growth in production and the 20% growth in reserves with this low finding cost, and that's really the hard part. We look at this as fairly extraordinary performance, and we think it's attributable directly to our very talented team -- technical teams which we're pleased to have. They really deserve all the credit for this kind of finding development costs combined with the kind of growth we've had. It's a real tribute to their effort and their capabilities.

When you look at the production growth, it's -- as CEO, it's very pleasing to see continue us deliver predictable transparent production growth. We've now extend our sequential production growth to 12 consecutive quarters. This consistently -- consistency is really attributable to three things, a solid base of long-life reserves, a large inventory of low risk drilling opportunities, and organization focused on delivering. At year end, our drilling inventory had risen to over 7700 drilling locations. And looking forward to 2006, as we've already mentioned, we plan to drill over 1,000 wells, which we anticipate will deliver another year of double-digit production growth. Also at year end, our acreage position stood at 3.3 million acreage gross, 2.8 million acres net. This is up significantly over the prior year period. A majority of this increase is attributed to a number of our emerging plays, and as Jeff will discuss later on, we're making very solid traction in a number of these emerging plays and are very excited about it. Lastly, at year end, finally, our low price oil and gas lots rolled off. As a result, we'll begin to see more of the benefit from the current oil gas price environment. And as most of you all know that follow us, this will have a very significant -- positive impact on our 2006 financial performance.

So those are what I consider to be the highlights of the year. And why don't we turn the call over to Roger to review the specific financial results. Roger?

Thanks, John.

Before I discuss the 2005 year end results, let me briefly recap the fourth quarter. The fourth quarter represented our 12th consecutive quarter of sequential production growth and was up 16.5% from the fourth quarter of '04 and 2.5% from the third quarter of '05. Realized oil and gas prices were 38% higher in the fourth quarter of this year than last year, and 8% higher than the third quarter of 2005. As has been the case for every quarter of the past two years, higher prices and higher production volumes drove steadily improving financial results. The fourth quarter of '05 was again a record quarter for revenues, income, cash flow and production. Total revenues for the quarter were 166.5 million, 63% higher than the prior year. A line item appearing for the first time in the fourth quarter is a pretax 10.9 million ineffectiveness gain on our hedge portfolio. As a result of the wider than normal gas differentials, certain of our natural gas hedges were required to be mark-to-market at year end, resulting in the 10.9 million pretax gain. This is purely an accounting issue. There was no change made to any of the underlying hedges.

As previously disclosed, direct operating expense for the quarter was $0.77 per mcfe, of which $0.10 per mcfe was attributable to work over expenses. Most of the work over expenses related to hurricane repairs. G&A expense for the quarter rose to $0.41 per mcfe, largely due to higher legal expenses and higher personnel expense. Our personnel count increased 14% in 2005, as we increased the number of wells drilled in 2005 by 77%. Interest expense per mcfe for the fourth quarter totaled $0.47 due to the higher market interest rates, as debt actually declined during the quarter. Fourth quarter DD&A rate reflect in the year end reserve figures was $1.49 an mcfe, up only $0.02 from the prior quarter. Non-cash stock compensation expense for the quarter of 5.8 million was attributable to mark-to-market accounting treatment of both our stock appreciation rights and Range stock held in the deferred compensation plan. Exploration expense of 9.8 million was within the expected range. It included 2.9 million in seismic costs and 4.5 million of dry hole expense. Please remember that Range's expenses are, in effect, fully loaded. As we capitalize no interest expense, no G&A expense or seismic expense and also we have no goodwill on our books and only 28.6 million in total unproved properties. And while we continue to maintain a Federal NOL carry-forward of 207 million, we did incur $740,000 in state income tax for the quarter.

Our margins improved as realized oil and gas prices improved, 8% from the third quarter and 38% from the prior year. As John alluded to earlier, but I just have to second, it is with great pleasure to report that the last of our low $4 per Mmbtu fixed price gas hedges rolled off at the end of the fourth quarter. Now, this will improve our margins going into the first quarter of '06, even with the recent gas price declines. Net income for the fourth quarter was 42.7 million, 193% higher than last year. This work out to $0.32 a share on a fully diluted basis. In numbers comparable to analysts' estimates for the quarter would be 41.5 million or $0.31 a share. EBITDAX for the fourth quarter totaled $120 million, 64% higher than the fourth quarter of last year; and 9% higher than the third quarter of this year. Fourth quarter cash flow was up 67% from 66 million to 110 million this year. For shareholder reference, as Rodney mentioned, these non-GAAP financial measures are fully reconciled on the Range Resources website.

Hedging activity for the fourth quarter and year to date consisted mostly of adding collars to 2007 and our first 2008 collars. We now have approximately 60 to 65% of our anticipated '06 production hedged, 45 to 50% of our '07 production hedged and approximately 20% of our '08 production hedged. The average gas price collar spread in '06 is a floor price of 6.37 per Mmbtu and a cap price of 8.70 for Mmbtu. 2007 has a floor price of 6.93 and a cap price of 9.63. The '08 collars have an average floor price of 7.81 and a cap of 11.75. The new '07 and '08 hedges' positions were placed in December and early January, before the recent pull back in the gas market. Now, for those of you seeking additional information about our hedge position, a detailed current summary of our hedging activity appears on the Range website.

Now, looking to all of '05, financial highlights for the year read similar to the highlights for the fourth quarter. Record revenues, income, cash flow and production. Revenues for the year totaled $536 million, 63% higher than '04. Net income available for common shareholders of 111 million was three times of that of '04. EBITDAX was 400 million in 2005, that's 73% higher than 2004. And cash flow was 363 million, 74% higher than '04. Higher revenue was driven by a 22% increase in production, combined with 37% higher realized oil and gas prices. As I mentioned earlier, the accounting treatment accorded certain of our -- of our gas hedges did result in the 10.9 million pretax gain for the quarter and year.

2005, like 2004, was a transition year for expenses, as oil service costs increased from heightened competition for services. Despite higher costs, our margins continued to improve in '05 as our lower price hedges continued to roll off and our production volume increased. Direct operating expense was $0.76 per mcfe for '05, up from $0.65 in '04. Now, of the $0.11 increase, $0.07 was due to higher work over expense, mostly off shore and hurricane related. Production taxes totaled $0.36 per mcfe this year, versus $0.29 last year due to higher oil and gas prices. G&A expense increased to $0.34 per mcfe in 2005, mostly due to the aforementioned personnel additions. Interest expense per mcfe was $0.44 in '05 compared to $0.32 in '04, mostly due to high -- higher interest rates and the issuance of 150 million in ten-year fixed rate 6.375% notes last March.

As an indicator of capital efficiency, which Jeff will talk more about in a moment, I am pleased to report that our DD&A rate increased only $0.07 in 2005, from $1.39 per mcfe last year to $1.46 in 2005. I believe these favorable DD&A rates reflect the quality of our assets, our drilling inventory, and our technical team. On the tax line, you'll note slightly over $1 million in current state income taxes for the year. But bottom line net income available for common shareholders, was 111 million for 2005, triple that of 2004.

Turning to the balance sheet for just a moment, debt decreased by 10.5 million during the fourth quarter and decreased 4.4 million for the year. Now, the balance sheet continued to grow stronger with the debt to cap ratio declining from 52% last year end to 47% this year end. continued improvement is evident in our other credit statistics as well. 2005 debt to EBITDAX is 1.5 times, down from 2.7 times at year end last year. And EBITDAX interest expense for the year is 10.3 times, up from 9.6 times at year end last year. The fourth quarter of 2005 also brought an upgrade from Moody's on our senior subordinated notes.

Looking to the future, I'm excited about what's in store for Range in 2006. With a stronger, simpler balance sheet, higher price realizations from our low price hedges expiring, an expanded inventory of drilling projects, additional emerging plays in the portfolio, and a larger, more capable technical team, we should continue to see favorable financial results. As John and Rodney mentioned, I look forward to seeing many of you and sharing more about our 2006 outlook at our analyst days next week in New York and Boston.

John, I'll turn it back to you.

Thanks, Roger. I'll now turn the call over to Jeff to review our exploration and development activities and status of our capital program. Jeff?

Thanks, John.

I'll begin by reviewing production. For the fourth quarter production averaged 250 million per day, a 16.5% increase over the fourth quarter of 2004 and a 2.5% increase over the third quarter of 2005. This represents the highest quarterly production rate in the Company's history, and the 12th consecutive quarter of sequential production growth. The 250 million per day is comprised of 130 million per day, or 52% from the southwest division; 97 million per day, or 39% from the Appalachia division; and 23 million per day, or 9% from the Gulf Coast. This increase was mainly due to the success of our drilling program. Approximately 72% of the Company's production was natural gas. For all of 2005, we achieved growth of 22% over 2004. I applaud our operating teams for a great year. These results were excellent and were achieved despite the impact of Hurricanes Katrina and Rita. We had a significant amount of production curtailed by both storms. At its peak, Katrina and Rita shut in 16 million per day and 33 million per day, respectively. Currently, only 2 million per day is shut in.

Reserve growth and finding costs were also excellent for 2005. We grew reserves 20%, at an all-in cost of $1.46 per mcfe. This is 365% replacement of production; and importantly, 249% is from drilling. Year end reserves totaled 1.4 Tcfe. Proved undeveloped reserves decreased from 37% to 34% of the total reserve volume. The Company's reserve life index stood 15.3 years based on fourth quarter volumes. Again, I applaud our operating teams for great year. Historically, our finding costs were also excellent with our three year average cost equal to $1.27 per mcfe.

I'll now review some of the highlights of each of our divisions. I'll start with the Appalachian division and begin with our properties in Virginia, which are the Nora and Haysi fields. These properties are continuing to outperform our original acquisition economics. Production is currently running about 30% higher than the original projection. For Nora field wells drilled to date, the average expected ultimate recovery is 400 million per well, from a depth of about 2500 feet. Drilling plans for the Nora coal bed methane field continue to ramp up with 97 wells drilled in '04, 159 in '05, and 200 planned for '06. Currently, there are 975 producing CBM wells in Nora. The Haysi field, which is the northeast extension of Nora field, also looks encouraging. We operate the Haysi coal bed methane field and own a 70% working interest and a 12.5% royalty in 30,000 acres there. We have drilled 23 coal bed methane wells on this property, and 13 of them are on-line. Results are encouraging, and we are planning on 35 wells in Haysi for 2006. Between Nora and Haysi fields, we believe that we have about 2700 locations to drill, assuming 60-acre spacing. Of the 2700 locations, only 624 are booked as proved undeveloped locations, which leaves over 2100 locations yet to be booked. Given our knowledge of the area, we feel that the probability of drilling these wells is very high. Given the quality of the production and because we own the minerals in the field, our finding costs are excellent, below $1per mcf, and our rates of return are outstanding as well. Our acreage position in this area consists of 287,000 gross acres.

I'll also give an update of our Widen property in West Virginia. This area contains a 77,000-acre block in which Range has 100% working interest and 100% revenue interest in 74,000 of the acres. I mentioned during a previous conference call that a CBM study of the properties had been completed and the analysis was encouraging. As a result of that study, we proceeded to the next step, which was to acquire coal bed methane cores and desorb them in order to quantify the gas content of the coal. The desorption process is complete and the analysis is encouraging. We will initiate a five well CBM project here this summer. Based on the data we have to date, a typical coal bed methane well here could potentially recover about 200 million cubic feet of gas per well from a depth of about 1800 feet. Cost to drill and complete is currently expected to be about 270,000 per well. This equates to about $1.35 per mcfe. Potentially, there could be as many as a 1,000 wells to drill, which gives an upside of about 200 Bcf net. I'll caution that it's still early and we need to drill our pilot project to confirm this analysis.

Our coal bed methane projects in Pennsylvania are also moving forward. We drilled 12 wells on our Unity acreage last year and are planning on drilling up to 15 additional wells this year. We're also planning on drilling 15 additional coal bed methane wells on our other projects in Pennsylvania. There'll be three 5 well pilots, one each on our [Chess Springs], [Welfred], and [Salem] projects. Combined, we have about 30,400 acres of coal bed methane potential in Pennsylvania.

Moving on to our shallow tight gas sand drilling in Ohio and Pennsylvania, we drilled 445 wells versus our original target of 380. This compares to 270 wells that we drilled in 2004. Ramping up the drilling increases the net present value as well as speeds the conversion of nonproducing reserves to producing, and unproven reserves to proven. Plan are to drill 479 wells in 2006. We have an inventory of more than 3300 tight gas sand wells to drill here. Next, I'll give an update of our shale gas project in Pennsylvania. Our first well, which was a vertical well, came on-line at a peak rate of about 800 mcf per day, and it's currently producing about 200 mcf. Reserves for this well appear to be in the 600 to 800 million cubic foot range. Given the results of the well, we just recently plugged back one of the wells that we drilled last summer, and fracked it with a large [Barnett stell fracked] as well. Currently the well is still cleaning up. We'll also plug back the other well which was completed deeper last summer and frac the shale within a week. We've also recently just finished drilling a new vertical well, which we'll complete in the shale, and we also just finished drilling and casing our first horizontal shale well. Within three months, we'll have the results from all five wells. In the meantime we have one vertical rig drilling and one horizontal rig drilling.

Given our current knowledge of the play, we believe that we currently have 300 -- 235,000 acres under lease that are prospective in this play. We're continuing to aggressively increase our lands holdings. And, again, I'm excited about the play -- the results of the first well. It's early, but given the reserves we see, the production rates we see, the fact that our acreage costs are extremely favorable, we're leasing acreage for typically in the 25 to $50 per acre range, able to get [inaudible] leases, and we get a gas price premium of $0.35 cents per mcf. It's early, but it's a very exciting play with lots of upside. The potential of the play could be over a Tcf of upside of net to us.

Our drilling program for the deep Trenton Black River includes five wells. Three in Bradford County in northern Pennsylvania, and two wells in Washington County in southwest Pennsylvania. Since these wells are deeper than our original -- than our shallow tight gas sand and coal bed methane wells, they require a bigger rig than we typically use in the basin. Also, since they're horizontal wall candidates, they require a rig with a top drive. Only one of the rigs that we have working in the basin can drill this type of well. We drilled two deep Trenton Black River wells during the second half of last year. One of the wells encountered dolomite with gas shows, which we'll attempt to complete; and the other well was a dry hole, encountering no dolomite. After drilling those two Trenton Black River wells, we moved the rig to the shale play and drilled our first horizontal shale well where we just ran pipe. We felt that using our top drive rig to accelerate our first horizontal shale well was the right thing to do. It allowed us time to finalize our joint venture with Talisman in southwest Pennsylvania, which we recently announced, and I'm very excited about partnering with Talisman, who is the industry leader in the Trenton Black River play. Currently, we're planning on spudding our Trenton Black River well in Southwest Pennsylvania in the second quarter. Talisman will operate the well, and we'll be 50/50 partners. We'll follow up that with the Bradford County drilling and completion later this year.

In the shallow portion of the Trenton Black River play in western New York, we drilled three successful exploratory wells which specifically targeted the Trenton Black River formation at about 3,000 feet. We have a 50% interest in these outside operated wells. It's been a long time getting these wells hooked up; however, these wells should be on-line soon. We have 91,000 gross acres in this portion of the play so we'll have some running room, and we'll follow up with additional drilling later this year.

In the Southwest division Range is continuing its infill drilling and refrac program in the west Fuhrman-Mascho unit in Andrews County, Texas, with continued success. We still have over 100 locations to drill as well as several wells to refrac. We also have significant upside with regard to water flooding. The Oil and Gas Investor just recently awarded Range's work here as the best field rejuvenation project in the U.S. Range has increased production in this 1930s vintage field from about 3 million cubic feet equivalent per day to over 20 million cubic feet equivalent per day, which is the highest producing rate in the history of this mature field.

One county to the west of Fuhrman, our new Eunice properties in southeast New Mexico are also performing well. We originally projected that we could double production on these properties by the end of '06. We're on track to do that, and have increased production from about 7 million per day to 12 million per day currently. We're also actively drilling and have had -- are having good success on our Conger and Val Verde properties. In east Texas, Range has 15,000 acres of lease holdings with working interests varying from 25% to 50%. And Range also has 30,000 acres of leasehold options. So far, we've drilled five wells. The first well was completed in the Woodbine for an initial rate of about 10 million per day gross, or 1.9 net over a year ago, and is still producing about 2.7 million per day, or 0.5 million per day net. The second well, which was drilled in the Woodbine, was dry and was plugged back and tested gas from the Austin Chalk. The third well was drilled to the Chalk and it came on-line in the fourth quarter last year at 13.3 million per day gross, or 3.7 million net, and it's currently making 9 million per day gross, or 2.7 net. We recently drilled the fourth well to the Woodbine, and decided to complete it in the Chalk, and this well should come on-line this week. The final well was drilled to the Woodbine, and we'll attempt to Woodbine completion in it shortly. We just recently spudded a new well which will be drilled to the Chalk.

In the Watonga/Chickasha trend of Oklahoma, we continue our drilling success there with two recent significant wells. In our last operations news release, we mentioned an Atoka/Morrow well that was producing at a rate of 15.8 million per day gross, or 4.6 net. That well is still producing about 8.1 per day gross or 2.4 net, and looks to be a very good well. We also recently drilled another well in the area and it is producing 2 million per day gross or 1.6 net. In north Oklahoma, we have a shallow drilling project that appears to have significant running room. So far we've drilled 34 wells and are pleased with the results. Typical wells are about 2700 feet deep, and cost about 350,000 to develop about 250 million cubic feet gross of reserves. We have identified about 200 potential drilling locations on our acreage with additional upside beyond that. We operate and have a 65% working interest in most of the wells there. In southern Oklahoma, we're in the process of drilling a deep 23,000-foot exploratory well to the Hunton formation. We have a 16% working interest in this first well. If successful, we have 12,000 acres in the play. Our working interest in this position averages 37%.

We also continue to have good success in the Texas Panhandle, and we'll continue to be an active driller there, with several potentially impactful wells to be drilled this year. I'm also excited about the shale projects that we've initiated in this division; and particularly, the Barnett Shale play that we have in the Fort Worth basin. We current have about 11,000 acres under lease, and are actively negotiating on other significant acreage positions. I'm also very pleased that we have hired Mark Whitley as Senior Vice President to both actively manage one of our divisions as well as to oversee and work with all of our divisions on the other shale plays that we have in the Company. Mark led Mitchell's efforts to unlock the potential of the Barnett Shale a play in the Fort Worth basin. Under his leadership, Mitchell's production in this play grew from about 60 million cubic foot equivalent per day to over 700 million cubic foot equivalent per day. I'm looking forward to seeing what Mark can accomplish here at Range. Our plans for our Fort Worth basin acreage are to shoot 3-D seismic in the second quarter and to begin drilling late in the third quarter. We also have 20,000 acres in Reeves and Culbertson Counties in west Texas. We believe this acreage is a prospective for the Barnett Shale, Woodford Shale, Fusselman and Wolfcamp formations. We plan on shooting 3-D here in the second quarter, and drilling late in the third quarter.

The Gulf Coast division drilled two exploratory wells during the fourth quarter. An onshore well in Cameron Parish was drilled 12,100 feet and was plugged and abandoned after finding thin, non-commercial pays. The other well was the West Cam 295 #3, which found 115 feet of gas pay in two zones. This well should commence production in April at over 10 million per day gross, or 1.2 net. The West Cam 295 #2 should come on line this week at a rate in excess of 20 million per day gross, or 2.4 net. Range will also have a 25% working interest in a high potential Norphlet well onshore Mississippi, which should spud in the second quarter of 2006.

In summary, we're in great shape to achieve double-digit production growth for 2006. 2006 will be an excellent year for Range and I'm excited and focused on the future. Range nw has approved reserve base of 1.4 Tcfe of solid long life properties. Our reserve life is 15 years. In addition to that, our drilling inventory consists of over 7700 locations that equate to 1.9 Tcf of net unrisk reserves, of which 74%, or 1.4 Tcf, is unbooked. This is a large, multi-year inventory of projects that consist mostly of low-risk, highly repeatable development projects, complemented with several higher-risk, higher potential exploration projects. In addition to that, Range also has 2 Tcf of net unrisk reserve potential in its emerging plays. These are primarily technically driven resource plays involving shale gas and coal bed methane opportunities within our existing core areas. So in total we have 1.4 Tcf of proved reserves, 1.4 Tcf of net unrisk unbooked reserves on our drilling inventory, and 2 Tcf of net unrisk reserves in emerging plays.

Importantly, we're not depending on one or two projects for our future growth. Having a large, high-quality drilling inventory is a real key in my mind. One of the key strengths of Range is its portfolio, the other is its people. This is led by a technical team that now consists of a total of 96 geologists, geophysicists, engineers and landmen. This is a talented group who is responsible for all of the projects that I've just mentioned, and they are continuing to generate attractive new opportunities. The Company today is significantly different than it was a year ago. With our 20% reserve growth last year, we now have over 1.4 Tcf of approved reserves. Importantly, the reserves that we've added are long-life, low decline rate, very predictable reserves. As a result, we now have a larger, more stable proved reserve base. We also have more upside with 3.4 Tcf of net unrisk reserve potential. As I've said before, it's a fairly simple business. The key is to grow production and reserves with good finding and lift cost, and to build and high-grade our inventory. We will stay focused on that. I feel confident that with our technical staff, large drilling inventory, and 3.3 million-acre position, we're well-positioned continue to add significant value.

Back to you, John.

Thanks, Jeff.

Why don't we now turn to 2006. Obviously, at least from our perspective, 2005 was terrific. But we're really focused, obviously, to the future. Just giving you some broad perspective, we continue to see for '06 strong operating performance. For the first quarter, we're looking at production of approximately 254 to 256 million a day. The midpoint of that is 11% increase year-over-year, so we're on target there. The first quarter '06 revenues should continue to increase with the higher production and stronger realized prices. As Roger discussed, at year end, the final tranch of our low priced oil and gas hedge finally rolled off. So our realized prices will move up significantly in '06. Assuming the current futures prices and the hedges we have in place, we anticipate first quarter price realizations to be in the $7.50 per mcfe range. This is 10% higher than what we realized in the fourth quarter of '05. And as a result, we anticipate production revenues, cash flow and earnings to all reach record levels again in the first quarter.

In my view, the first quarter of '06 -- the year-over-year comparisons will be very important, in that they'll bring together in a very tangible fashion all that we've achieved over the last 12 months. It starts with production, which as I previously mentioned, is anticipated to increase approximately 11%. And that all will be through the drill bit. Second, realized prices with the rolling off of the lower price swaps are estimated to increase by $2.50 per mcfe versus the first quarter of 2005. So you can see the impact there. And, again, they'll be about $0.70 higher than the fourth quarter of '05. So as a result, revenues for the first quarter we're looking at somewhere in the $175 million range for the first quarter of '06. This will represent the highest quarterly revenue in our history, breaking the previous record by more than $40 million. While revenues will increased dramatically, expenses are anticipated to increase to -- at a more modest rate, and as a result, bottom line earning are anticipated to increase significantly, with cash flow and EBITDAX also reaching new record highs.

Looking beyond the first quarter, we anticipate '06 production to increase each quarter. If successful, this will extend our production growth to 16 consecutive quarters. So that's obviously something that we're very focused on. As I mentioned earlier, we're still looking at solid double-digit production growth for the year. I feel very good about that. Based on current futures prices, we anticipate both earnings and cash flow from operations will increase by over 50% in 2006 versus 2005. So as you see, 2006 really shapes up to be a remarkable year for Range's shareholders; and I'm glad and our management team is also glad that we own a lot of the stock ourselves.

While as Jeff and Roger mentioned, we've accomplished a lot. We accomplished a lot in '05. I believe the majority of our efforts will really benefit what we're doing in '06 and beyond. As you heard from Jeff, we now have projects in the pipeline that have over 3 Tcf of unrisk reserve potential. That's more than twice our existing proved reserves. Over the long-term, I really believe shareholder value is determined by the degree of success an oil and gas company has in generating attractive returns through the wise investment of capital. The efforts and quality of our technical teams are critical to this process. We all realize that. At Range, we've built what I believe is one of the highest quality technical teams in our peer group. They're generating very attractive opportunities in each one of our areas of operation. We enter 2006 with the largest drilling inventory in our history with over 7700 projects, comprised of a large -- a very large number of lower-risk development exploitation projects and a diversified group of higher-risk, higher potential exploration projects.

I really see Range as unique in that, for our size, we really do have a very large transparent drilling inventory. We also have a growing number of very exciting emerging plays, a number of which Jeff mentioned. And we have the largest acreage position of 3.3 million gross acres. As you all know, we've worked tenaciously at building our drilling inventory and lease hold position, and we really think this is the key drivers to long-term growth and profitability. That being said, we really do fully understand that the key here is continued execution of our strategy. Day-to-day, our team of professionals -- they're really focused on continuing to execute and delivering attractive returns on the capital that they're and shepards over. That being said, Jeff and I and the rest of the management team really continue strict vigilance and discipline. For example, as Roger mentioned, we're keenly aware of the recent increases in oil field service costs; and Jeff and I continue to prove every material capital expenditure in this Company. We'll only spend capital if the project, based on up-to-date costs, provide attractive returns. If not, we will not spend then money. As shown by the methodical building of our drilling inventory over many years, we will not sacrifice long-term -- we will not sacrifice long-term for non-repeatable short term gains.

Looking over the hill, we're -- we really feel like we're in superb position to add materially to our shareholder value over the next several years; and we're really keenly focused on delivering. Like Jeff, I'd really like to publicly congratulate and thank our talented team of nearly 600 employees for a job exceedingly well done in 2005. We've set a very high bar for 2006, and I'm confident that with the talent, the dedication, and passion of the Range, team we will meet or exceed our goals for 2006. Lastly, I would -- like the others, I would really encourage to you attend our analysts meetings last week. A number of our key technical people will present, and they have some very exciting presentations. And I think you'll see those as quite insightful, and as Rodney mentioned, there'll be a number of slides that are confidential. So we won't have them on the website, so I really encourage you to be there in person if you can.

With that, operator, that's our planned presentation. Why don't we turn the call over to questions?

[OPERATOR INSTRUCTIONS]. Andrew O'Connor, Wells Capital Management.

Well, good afternoon, guys.

Andy.

Since your operations update of February 2nd, I noticed that Range has added about 69,000 acres to its shale lease hold position. I think it was from 166,000 to 235,000 acres. Can you tell us more about the acres that you've added recently?

Yes. I can -- we've identified characteristics we think that are important to making the shale play work. Again, I'm really excited about having Mark Whitney as part of our team team. We have a strong team in-house, but Mark with his expertise in the shale plays is as good as it gets. So with the criteria we've identified and with our initial testing, we've identified certain parts of the basin that we think are very attractive and are aggressively really out ahead of the industry leasing those areas.

Okay. Hey, Jeff, how many acres do you think you'll have by year end '06?

I don't want to make that kind of prediction; but what I will say, what I said was in a short period we're going to have results on five wells and coupled with that we have one horizontal rig working and one vertical well. To the extent we cost to get good results, we'll just continue to lease because we think there's a lot of running room to the play.

Andy, this is John. I think to add to what Jeff said is that -- he kind of went over it fairly quickly in his presentation, but the interesting thing about this is that our average cost per acre's, let's say, in the $50 range. So to the extent that we're out there leasing, we have a boat load of people out there on the ground leasing, so we're very active. It's not like we're spending all the money that we've got left in the piggy bank here. So we're -- we're being -- although we're being aggressive, I think we're doing it the right way and we're doing it in areas that we feel very confident that -- or have shale potential. But also there's some tight gas sand even deeper in a number of these plays that give us some secondary objectives, too. So I think it's very well thought out. We're not going to -- we're not going to go crazy here, but we are being very aggressive, and, again, at $50 an acre, we're not going to get ourselves in too much trouble.

Okay. Thanks very much.

And, Andy, this will be a large part of what we're presenting in New York and Boston is some detail on this that you'll probably find very interesting.

Okay. And I was just trying to get a sense for how aggressive, John, 69,000 acres in just two or three weeks time. I thought maybe the acreage position here by the end of the year would be quite a bit bigger than it currently is.

Well, I certainly hope it is; but that being said, the interesting thing here is that we're not talking about large ranches like you may have in west Texas or even in the Barnett play here in Fort Worth where you can lease 2, 3, 4, 5000 acres at a pop. I think our average track size that we're leasing is around 200 acres a pop. So it's a lot of very tedious work. So our land team up there is just doing an incredible job of leasing, so I'm really proud of what they're doing. Would I love -- I'd love to have double the acreage position we have today, but again, it's starting -- the competition is starting to be in there but we've got -- like Jeff said, we've got in [inaudible] we've got the -- we're ahead of the competition, and we're doing a good job and we'll continue to be aggressive and see where we can end up at. But I'd love to see double the position we're at. But that being said we'll -- we'll just -- every quarter we'll give you an update on it and tell you where we are.

Thank you. Good luck, guys.

Rehan Rashid, Friedman Billings Ramsey.

Rodney, just a couple of quick modeling questions and then a broader operations question for Jeff. Just in terms of '06, is the fourth quarter G&A run rate good? How should we think about deferred taxes, maybe not just for this year because you still probably have some NOLs leftover, but going out into '07? And -- yes. And then I'll wait to ask some questions for Jeff.

I'll say a few things and let Roger kind of fill in some details, too, Rehan. When you look at the G&A in the fourth quarter, it's significantly impacted with some legal costs, et cetera. But if you look at it on a go-forward basis, that per mcfe type of cost should be somewhat in the range and we'll keep you advised of that. Analyst day will give you some specific direction on those, and it will be on the webcast. And as Roger stated on taxes, those are mostly deferred. It's only going to be in those states where we don't have enough IDC to offset the income. So that will run about $1 million a year right now in cash taxes. I don't think that will appreciably get larger as we go forward. Roger, do you have other comments on that?

No, I think you hit it, Rodney. I think the $1 million a year in state income taxes should be going down as we get a better handle on the acquisitions and how to optimize our structure there.

Okay. Thanks. On the operational front, could you talk a little bit more about -- Jeff or Mark, that what is the -- what was that acreage that we talked about in the Barnett Shale? What's the plan there again? And on the Appalachia side, the five wells -- the five data points [inaudible] that you would get hopefully soon in the next three months, should that -- I mean, how much of a comfort does that give you that you're well on your way to kind of work towards the upside potential that we talked about there?

Okay. I'll say this. Mark is not on the call. Mark will be in New York and Boston and he has a great presentation on the Barnett Shale, as well as Mark will be commenting on all of our shale plays, including the Appalachian. So -- and he has some great insight on all that, so I'd recommend you attend to hear that, or listen in to hear that. But I'll speak to both of those things.

In the Fort Worth basin, our plans are we have 11,000 acres. We're negotiating for a lot of additional acreage. We're really excited about the play. The play, we really put together before Mark got here, that I had a lot of confidence in and our team did, including guys who have good experience in the trend. And when Mark came on board, I was really -- first thing I wanted to do was to have Mark really review it in detail, which he did; and Mark really likes the concept, likes the play, he's going to present it next week. And he's leading our effort now to expand that, and he'll [inaudible]. We'll be shooting 3-D seismic in the second quarter, and we have a rig scheduled to come late in the third quarter to drill our first well. So that's where we are in the Barnett in the Fort Worth basin.

Out in the Permian Basin, we'll be shooting -- it's a similar type story. We're shooting 3-D there in the second quarter, drilling late in the third quarter. It's a little bit different in the Fort Worth basin, obviously, it's a prove -- we're in a proven play where the Barnett's making over 1.2 Bcf per day. In the Fort Worth basin, it's exploratory, it's a new play; but what I -- so what I like about that, though, is we have [sat] pay potential there, similar to what we do in the Appalachia basin. We see Fusselman targets, Wolfcamp targets, Woodford and Barnett targets.

And then to try to answer your question, in the Appalachia basin we have one control point so far well with -- that's been on-line for a well and has good history, it's performing well. It's actually outperforming our original modeling. And based on that, we recompleted some of these wells that found deeper plays. We just recompleted one of them about week ago, and this weekend we'll do a second. And, again, because some of these shale plays have become good horizontal plays, we just finished drilling and completing our first horizontal shale well, and for the year at a minimum we'll drill 10 vertical wells and 3 horizontal wells. So I think part of that depends -- there's always a learning curve in these resource plays, but we're off to a good start, literally just within a few months. We're going to have a lot of -- a lot more control points and we'll go from there. And with the talented group we have up in the Appalachian basin, really working with Mark, I'm really excited to see what those guys can accomplish.

Got you. Two more quick questions. Going back to Nora Haysi, I had remembered in looking at my notes the upside potential that was roughly unbooked I have it as roughly 400 Bcf. I think the math that you guys had used to guide us -- or at least for me to get there was 8 feet of coal per well and maybe 0.325 Bcf's per well. Based on your production results in the area being significantly ahead of what you were thinking and/or more recent drilling results, should that kind of recovery rate and those kind of feet of coal per well still holds, or does -- has that gotten better?

Let me talk about that a little bit. And I think the last number I remember off of our slides is in the range that you said. The important part about that is, again, there's a lot of undrilled locations. There's a lot of upside. It's very low risk, it's pretty well defined. There's a lot of control points. Because we own a revenue interest -- or we own the royalty along with the working interests, our finding costs are below $1, and we have very strong rates of return. There is upside there, [Console] on their side of the field over on Oakwood. It's down spacing to 40 acres. Down spacing will lead to more locations; down spacing can potentially add to increased recovery. So there is upside beyond the numbers to what you're saying. And the good news, again, it's a big upside and it's unique in the fact that it's very low risk.

Got you. And, John, just on a -- on broadly [barter] speaking, F&D for '06. Would it be okay for to us assume the same kind of '05 numbers? And also current reserve life at 16 years, as we book some more of these long-lived assets, the reserve life has continued to expand quite significantly. How long of a reserve life will be enough before you kind of maybe come back towards some more shorter life assets, or do something to accelerate production even more?

Looking on the -- looking at the FD&A, if you -- if you just take the $1.46 and you assume a 20% increase in service costs which is plus or minus what we're seeing out there, that gets you at $1.70 to $1.75. So I feel -- if there was no increase in service costs, I'd be very confident with last year's FD&A number. I think you just take whatever increase in service costs you believe is going to be out there, and add it to ours, and -- because we're not going to be -- we're not going to be any different than anybody else on an overall basis. We're all subject to those increases. The good news is, is that the thing that will continue to buffer that -- and this is, again, kind of a nuance about Range, I think is a little bit underappreciated is, is that as we continue to add coal bed methane and [technical difficulties] we -- as we continue to ramp up production from our CBM not only in Nora but also in Haysi, which is very exciting and some of the things we're doing in West Virginia and Pennsylvania. As we do that, plus as we drill some of the shale stuff, that will have two impacts. One, it will lower our overall decline curve and therefore make double-digit production growth, quote, easier to -- if you want to call it easy, you'll make it easier to do each year, which is obviously the challenge in this business. The second thing is it will tend to soften the impact of the service increases. So there is a real method to the madness here in terms of what we're doing. In terms of -- one was service costs -- what was the other one?

Just as long as you do add the CBM plays and shale plays, life -- reserve life continues to increase, and kind of in your opinion is it 25-year life or 25-year life good or what will you do to kind of lower that life of -- or oil reserve base and maximize --

Well, yes. It's the chicken or the egg. I think, as you know, we are -- we've really ramped up our drilling of our tight gas sands, as Jeff said, just to speed up the net present value and to -- given our acreage position, as we drill one of these tight gas sands, you tend to drill one and book another one the way we book things, because we -- we have a strict policy, we only book one offset to a producing well. So we don't use the statistical analysis approach. But that being said, reserve life -- I'd love for it to -- if we could speed it up and get it to 10 years I'd love to do that. That being said, we're going to be prudent and whatnot, so I don't get too worked up over reserve life. I -- all I want is continuing double-digit production growth every year, and hopefully good solid reserve growth at good finding costs. The reserve life will just be a function of that.

Thank you.

Pavel Molchanov, Raymond James.

Hi. Good afternoon. Question about your -- your balance sheet. Can you talk a little bit about the -- where you see your debt to cap and your other leverage ratios in about 12 months? And in a similar vein, what would your priorities be for any cash flow that you generate in 2006?

That's a very good question. I think -- one of the things -- we -- just to give you -- broadly speaking, we, for several years now, have said that our target debt to cap is 40%. The good news is, is that hopefully by -- in the next quarter or two we'll clearly be there there. So I think that is kind of step one.

The harder thing is what we do with the excess cash flow that we're going to generate this year over our capital expenditure budget. Based on the current strip and the hedges we have in line and everything else, just broadly speaking, we're going to spend our capital budget as we've got it laid out today. We'll consume about 75% of our cash flow. Now, that does not -- our budget -- that being said, our budget does not include any monies for acquisitions. We do not budget acquisitions. We look at those as very opportunistic; and if we're successfully at them, good; if we're not -- but the last thing I want to do is give my acquisitions team a budget and tell them they have to spend that money. That will certainly generate excessively high DD&A rates. So -- but the real question is, can we find some attractive acquisitions to use that fair cash flow? If we can, great. The other thing is if we have some success at some of or exploration projects that will generate some add on drilling. We'll expand our drilling capital, which would be great. And then lastly, some of these emerging plays that we're doing, if we get some of the results that we want, you could see some significant speed up on there. In particular the -- either the shale play in Pennsylvania or the Barnett Shale play in Fort Worth, you could see that speed up a little bit. So those are kind of the three primary users of the excess capital; and obviously, we would want similar returns that we're making off our existing capital budget to do that.

That being said, I think one of the things the Board is -- we focused on over the last Board meeting or two, and we're going to focus on again in the next one is where we are in terms of evaluation and what we do with it. I am not a big believer, at least personally, that once we get to a 40% debt to cap, that paying off 4 or 5% bank debt is particularly interesting to me. But again, it's -- I'm only one of the Board members out of eight, and so we'll let them -- let them decide. But -- and then also that couple -- and I'm not trying to be vague, but just give you kind of the outline. The other thing is, is that as we gain more traction and more confidence in some of these other merging plays, that'll have a big impact in terms of what we do at that -- with that capital as well, in terms of wanting to spend on new projects, or, quite frankly, buying back our stock. So it's kind of a -- there's a lot of different assumptions, as we all know, in that equation, but the good news is we could have some of those interest discussions in the second half of this year, which would be great.

All right. Thanks very much.

Ron Mills, Johnson Rice.

Good afternoon. I was calling just on the -- really the Talisman venture that you all talked about on -- or announced in February. Can you expand a little bit in terms of what some of the terms of the deal are, for -- and where the acreage relates to some of the Talisman success of the past?

We -- Ron, this is John. And I'll speak to it in a broad sense, then I'll let Jeff chime in on the things that I missed. We really have -- if you want to call it -- we've got 3 three TBR focused areas. One is in a northern part of New York, and that's the shallow stuff. As Jeff spoke about, it's 3,000 feet. We drilled some good wells, and we're having just a hell of a time getting the son of a guns hooked up; but hopefully, we'll have them hooked up here in the next month or two, and we're actually selling gas, which will be a true event. And this is out in the middle of an area, believe it or not, that really doesn't have the kind of pipeline system that we need. But -- so we're there, and it's been painful, but we'll get that gas on line. If that works then we'll drill a bunch of more wells. We've got about 90,000 acres, as Jeff said.

So that's kind of number one. Number two is the southern part -- is the northern part of Pennsylvania and the southern part of New York right there -- the border -- we call it the Bradford County, because it happens to be -- most of the acreage is in Bradford County, Pennsylvania. That's the second play, and that's the deeper part. We drilled a couple of wells. We've had one dry hole in one well that we did have dolomite, and we're going to attempt a completion on that shortly. So that's kind of the second area, and we've got 116,000 acres with about 65, 68% working interest in. And we've got some more 3-Ds we've done, and we've got some more wells to drill there, some more anomalies. And that is right smack in the middle of where Talisman has drilled and some of the others have drilled some fabulous wells. We hope to drill some fabulous wells there in the future, but we just haven't done it yet.

So that's area number two. Now, area number three is probably where we've talked the least amount about, and that's down in south western Pennsylvania on the southern and western side of the state. And that is where we've done some seismic work and Talisman had seismic work as well. We own acreage all amongst each other, and what -- really what it came down to is that there were some seismic we'd shot, they'd had privy of it, we'd had privy of it. And we simply just combined our acreage. It's two blocks of acreage that totals about 17,000 acres. And we will own 50% working interest in that block of acreage. Talisman will own 50% working interest in that acreage. Talisman will operate -- drill and operate the deeper wells of the Trenton Black River wells. Range will be responsible for drilling and operating the shallow tight gas wells and potentially some shale wells if there are some in there. So it's really -- what we're doing is trying to combine the strengths of both companies. They -- as Jeff said, they are clearly the leader in the Trenton Black River. As I tell people, it's kind of them and the rest of us are the seven dwarfs. So we're excited about having them in there and leading the way. And -- so it's a perfect fit of what our respective strengths are, and we're excited about getting the first well drilled, which the latest I've heard Jeff is, what, second quarter?

Yes. Hopefully, relatively early in the second quarter is what we're currently thinking.

Okay. So the Talisman arrangement is really in -- on those 17,000 acres in southwest Pennsylvania, but not in the stuff to -- in northern Pennsylvania?

That's correct.

Okay. And then in northern Pennsylvania, would you -- do you expect to have some activity following the well with Talisman? Is that what you suggested earlier?

Well, we've got some anomalies -- some [grobbins] that are mapped, and we're going to drill those grobbins. As Jeff said, there's only so many top drive rigs in the basin, so we've got to allocate that rig between shale play -- the shale horizontal wells and the TBR wells, and it's just a question of which comes first. From our perspective, the shale play has so much more upside on a relative basis that we -- it was really just driving me nutty that we hadn't gotten a horizontal well, so I think I just -- finally Jeff and I just told them, just move the rigs and start drilling some horizontal wells. We want to see what's happening, because, again, we're leasing a lot of acreage. We've got a lot of land people on the ground, and we just really need to understand whether this is going to be a vertical play, or a horizontal play, and that's why we're drilling a combination of both vertical wells and horizontal wells, so we can figure out what kind of play it is. We've got a some--we've got a vertical test that's commercial, we're very excited about--if a--on an analogy basis, if you get the same increase in reserves and production, in the Barnett--I mean, up there as you did in the Barnett from the vertical and the horizontal we'll be--you'll be scraping me off the ceiling. But, again, we just don't know that yet. The only way we're going to know it is drill the stinking wells, so that's what we're going. We're going out there and just drilling the stinking wells.

Okay. And then as we move further south to your Southwest division, the Oklahoma -- the Watonga/Chickasha trend, you obviously had a real nice well that you announced. What are -- can you provide, I guess, Jeff, a little bit more specifics in terms of what kind of ramping activity on that acreage that you're expecting? As I recall, this was acreage from a farm out and that was some of your early activity on that acreage. Is -- what's the plan for 2006 there?

Well, our plan really is to run one -- one full time rig in Watonga/Chickasha and at times, we'll probably have a couple of rigs drilling in that area. The good news is in and around where that discovery is we have on the order of 15 to 20 additional locations. So it's a -- the Watonga/Chickasha area in general for us has been a great area, it's a stack pay area. We have a 90%-plus success rate, good finding costs. Strong rate -- very strong rates of return because you can -- a typical well can IP in the 1 to 3 million per day range, so you get great rates of return, great finding cost, and then periodically in there, you find some of these really high-end wells like this that literally will pay out within two to three weeks. The good news is there's running room in the area, and we're really excited about it. So we will continue to drill in there and -- now, those guys overall, if you look at their whole division and step back from it, have done a great job driving production over the last three years from about 10 million per day to now to over 40 million per day, with great finding and lift costs. So I have high hopes for them in the Watonga/Chickasha as well as this northern Oklahoma play, continue drilling on Courson Ranch in the Panhandle, and in our deep Hunton play in southern Oklahoma. There's lots of exciting projects in that division.

Okay. And then you've been -- what's that?

And, Rob, by the way, Paul Blanchard, who runs that division, and Greg [Quana], who's the chief geologist, they will be at the analyst day. So, again, we're -- really what's happening, just to give you a little bit of insight on this analyst day, basically, Jeff and I are going along just to kind of introduce people, because you're not going to hear much from us. Who you're really going to hear from are the Paul Blanchards who runs Midcontinent; Steve Gross, who's running Appalachia; Mark Whitley, Permian east Texas, Mark Whitley and some of the shale plays; Bill [Digorski], chief geologist Appalachia; Martin [Emory], chief geologist for some of the stuff we're doing down here, as well as the guys -- [Jerry Grantham], who's doing our coal bed methane work; and then last but not least, the great Steve [Currie], who runs our Gulf Coast and has got some exciting onshore projects. So those are peal people you're really going to here from. I'm going to do -- and Jeff and I are going to do very little, quite frankly, and they're -- you're going to get to see what they do on a day-to-day basis. They're going to have work maps. They're going to show you what's going on. The wells we're going to drill. Some of the upside. And we're going to let you guys quantify the upside and whatnot on your own. And we'll give you the numbers, but you all can risk them like you want to risk them.

But I think it's really going to be an eye-opening experience, because I think it's really going to show the depth of the technical team and some of the exciting projects they're working on. And that's really what Range is all about, is very, very high quality technical people. And the reason why we've been successful is that those guys are really generating the opportunities. Jeff and I and Roger, Rodney, and some of the others -- we're not generating these opportunities. It's really them. We're just -- we're just sitting on the front of the bus and enjoying the ride, so to speak. So, in this analysts day, you're really going to get to see that firsthand, because they're going to do 90%, 95% of the talking. So I think -- I'd really encourage you to come, and you're really going to get a sense of that. And we're going to try to keep it not so technical that it's going to blow everybody away, but I think there'll be a little bit of detailed technical work in there just so that you can get a sense of they're technical abilities and what they're doing.

Okay. And then finally, just as we move to the Woodbine area, I know the Chalk had -- two or three quarters ago was talked about as an area of potential. It sounds like you finally completed a well there. Is that a play that you'll actually start targeting as a primary zone in the Woodbine area, or is -- are you still going to try to drill down to the Woodbine and still the Chalk as a -- as a [pine pipe] type zone?

Well, within -- within that roughly 40 thousand acres of both leases and options, there's potential, and part of it's for Chalk and part of it's for Woodbine, and part of it's back together. So it really depends on where you are within there. You won't see us running out along trends and becoming Chalk players, but to the extent that we have good caulk potential on the existing acreage we have, we'll certainly drill those wells as long as they have good finding costs and strong rates of return. The first well that we put on is excellent. I mean, it'll be -- I'll say a well in the -- probably 6 to 8 Bcf range with very quick pay out. Rate of return well over 100%. So it's -- to the extent we can do that, we'll do that all day long, but our plans are to just exploit that stack pay opportunities we have in there, and then it's early, but so far, we're encouraged by what we see.

Okay. Thank you guys.

Jack Aydin, KeyBanc.

Roger, for -- question for you. With the natural gas prices around the $7 area, is there a risk for ceiling test in the first quarter?

No, Jack. We don't anticipate any -- any issues there at all.

Okay. Thank you.

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

Oh, well, thank you, operator. Just a -- just to give my comment on that question, Jack. I think it's an interesting question. And I will personally strangle anybody that has an impairment at $7 gas. That's not what we're all about. But that's certainly an interesting question. I hadn't thought about that in that perspective. The good thing is we're successful effort, so we write off dry holes and we write run off seismic. So we don't have a lot of stranded cost on the books. Thanks goodness.

In terms of wrapping this up, we -- we feel we're in a unique position. As I mentioned, we've got a big drill inventory. We've got 3.3 million acres -- gross acres under lease. But most important, we've got a great technical team that's really just hitting the ball out of the park. And I think Mark Whitley, although we've talked about his a bit, is just -- is a data point for you all in terms of our ability to attract and retain what we believe is a very exciting motivated team of people. And that's really what drive in Range Resources. The good news is we're still small enough that these plays can have enormous impact in terms of value per share. And that's what we're all about, is trying to drive up the value per share here. We're not necessarily interested in having the largest market cap, we're just interested in having the largest increase in stock price.

Again, I encourage you all that are in the area that would like to make the effort to attend our analyst meetings next week. They're going to be quite informative, as I mentioned; and we really appreciate all of the support from all the shareholders that we've had in 2005 and before. We think -- we appreciate you all's efforts. We think we have at least attempted to gain your credibility and trust as we go through this process, and we really look forward to a terrific 2006 as we embark with gas prices -- realized gas prices that are more in-tune with current market versus being -- having a ball and chain around our foot, as we've had with these low priced hedges. So it's a pretty exciting time here, and we look forward to terrific first quarter and full year results in '06, and I hope to see a lot of you all at the meetings next week. And, operator, that's it from here.

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