山脈資源 (RRC) 2008 Q4 法說會逐字稿

Welcome to the Range Resources 2008 earnings 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 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 Resources reported results for the fourth quarter and 2008 year with record production, revenues, cash flow and earnings both in absolute dollar amounts and on a per share basis. 2008 marks our sixth consecutive years of sequential production growth with 24 consecutive quarters of sequential production growth. Drill bit finding costs for the year came in at $1.70 per mcfe and drill bit reserve replacement was 367% of our 2008 production. We have posted on our website supplemental tables to assist you in understanding many of the numbers in the press release. In the press release we furnished some non-GAAP reconciliations which allow you to compare our results to our historically reported numbers, which include the Gulf of Mexico operations that we sold during 2007.

In table five of the supplemental tables we presented a summary of the non-GAAP numbers which correspond to the analyst models taking out certain noncash items. On the call today with me are John Pinkerton, our Chairman and Chief Executive Officer, Jeff Ventura, our President and Chief Operating Officer, and Roger Manny, our Executive Vice President and Chief Financial Officer. Before turning the call over to John I'd like to cover a few administrative items. First, we did file our 10(K) with the SEC this morning. It is available on the home page of our website or you can access using 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.

Tables are also posted on the website that will give you detailed information of our current hedge position by quarter. Second, we will be participating in several conferences in March and April, check our website for a complete listing. We will be at the Simmons Energy conference in Las Vegas on March 5th and 6th, the Raymond James Institutional Investor conference in Orlando on March 9th and 10th, Howard Weil conference in New Orleans on the 24th and 25th of March, and the IPAA Oil and Gas conference in New York on April 21st.. Now let me turn the call over to John.

Thanks, Rodney. Before Roger reviews the financial results, I'll review some of the key accomplishments for 2008. On a year-over-year basis production roses 20%, beating the high-end of our guidance. Fourth quarter production averaged 403 million a day, a record high representing the first time in Range's history that quarterly production exceeded 400 million a day. It also represents the 24th consecutive quarter of sequential production growth. I should note that no other company in our peer group has achieved that particular goal. This is a vivid testimony to the quality, in my opinion, of our operating teams. At year-end 2008 reserves totaled, proved reserves totaled 2.7 Tcf, a 19% increase over 2007. As Rodney mentioned, reserve replacement from all sources was 405%, including all revisions. Our drilling program alone delivered 367% reserve replacement at a cost of $1.70 per mcfe.

Based on what we've seen to date, these look to be in the top 10% of our peer group. In addition to adding roughly half a Tcf of proved reserves, we added 400,000 net acres to our leasehold inventory at an average cost of approximately $1,500 per acre. Most of the acreage was added in our Marcellus Shale play in Appalachian. Next we combined -- at the end of the day we combined exceptional growth in production of reserves with low finding cost. That's the hard part in our business, combining high growth with low cost. Again, this performance is attributable directly to the very talented technical teams that are with Range. In 2008 we completed $68 million of asset sales. Over the last three years we've sold $303 million of properties. We believe periodically selling our more mature properties have several benefits. First, it helps us focus on higher growth opportunities.

Second, it provides additional capital to spend on high return activities. Third, it helps high-grade our property base. Fourth, asset sales reduce the need to issue equity. We plan to continue selling non-core properties from time to time. Although not the best market, we are considering selling a few properties in 2009. We will only pull the trigger if we see reasonable prices. If not, we will hold on to the properties and look to sell them later. I'm proud -- when you look at 2008 I am really proud of what we didn't do. In particular, we didn't do a lot of high priced acquisitions that would have negatively affected our low cost structure for many years. While we had plenty of opportunities to acquire properties in our core areas during 2008, our bidding strategy was focused on maintaining our low cost structure. As a result, we were severely outbid on all these property potential acquisitions. With that I will turn the call over to Roger to review our financial results.

Thanks, John. Let me start by recapping full year 2008 financial performance before discussing the fourth quarter. Some of the key financial highlights of '08 include, one, achieving record high annual EBITDAX of $955 million and record high annual cash flow of $853 million. These measures were both 27% higher than last year. Two, ending the year with over 70% of our production hedged and securing additional hedges in early '09, bringing our hedge position up to approximately 81% of our anticipated '09 gas production. And that's at a floor price of $7.62 in Mmbtu. Third, we issued $250 million of ten-year senior subordinated notes last April at 7.25%. We did that to refinance bank debt. And we also sold 282 million of common stock to acquire promising Marcellus Shale acreage at very attractive prices. Fourth, we increased our liquidity by raising our committed bank credit facility from $900 million to $1.250 billion in a challenging bank credit market.

Cash margin for the year was $6.04 per mcfe or 7% higher than the $5.67 per mcfe figure from last year. Net income from continuing operations for the year was $346 million, up 107% from last year's $167 million figure. Now net income calculated as analysts typically do, which excludes asset sale gains, hedging mark-to-market gains and other non-cash items, was $309 million or $1.98 per fully diluted share. This compares favorably to the analyst consensus earnings per share estimate of $1.80 for 2008. Cash flow per fully diluted share in 2008 was $5.47, a 22% increase from 2007. Now this '08 cash flow per share result was $0.04 above the analyst consensus estimate of $5.43. As always please view the Range earnings news release and visit the Range website for detailed reconciliations of these non-GAAP measures.

Now the details behind '08 were very similar to prior years, with steady increases in production volume and, to a lesser extent this year, in proving oil and gas prices, out pacing increases in operating costs. The average price received for oil and gas sales this year, including the hedges on those volumes, increased by 7% from 803 in mcfe to 858 per mcfe. As John often reminds us and as he just mentioned, sometimes the best deals you do for the Company are the ones you not do. And by relying on steady drill bit growth, refraining from high priced proved reserve acquisitions, and by financing our unproved acreage purchases with common equity and ten-year fixed rate notes, we were able to end 2008 as a larger Company, but with essentially the same quality balance sheet as we entered the year. Our book to -- book debt to cap ratio was 42% at the end of the year. That's compared to 40% at the beginning of '08.

Now we ended the year with over $0.5 billion in committed unused credit capacity under the bank credit facility. Also we added four new banks to the credit facility in '08, further reducing our alliance upon any single bank. Now the largest share of the credit facility held by any one bank has been reduced to just below 5%. Lastly, we pressure tested our $1.5 billion bank credit facility borrowing base by running our year-end proved reserves using the current agent bank '09 gas and oil price assumptions that start at 450 per Mmbtu and $40 a barrel. The result shows that our maximum conforming borrowing base capacity remains approximately $2.2 billion, as our proved reserve additions in '08 have offset the impact of declining prices. So our $1.5 billion borrowing base has already been tested in the current commodity price environment and we feel like we are in great shape.

Direct operating expenses, excluding noncash compensation expense, on a unit cost basis were $0.99 per mcfe for the year, up from $0.92 last year. G&A expense, excluding noncash comp, for the year was $0.49 per mcfe, compared to $0.44 last year. Just expense for the year was $0.71 per mcfe compared to $0.67 in '07. And lastly DD&A expense for the year was $2.12 per mcfe compared to last year's $1.89 figure. Our all-in cash and noncash total unit cost expense for '08 was 8% higher than '07. And while cost increases are never welcome, we are pleased with this performance considering record high 2008 oil and gas prices made for an intensely competitive year for oil and gas industry services. Turning to the fourth quarter of 2008, the good news in the fourth quarter was a 17% increase in production over last year and our second quarter in a row of declining direct operating unit cost.

The bad news was a 21% decrease in wellhead oil and gas prices from the fourth quarter of last year, leading to a 17% decline in our oil and gas price received after hedging. Now the result of fourth quarter prices falling faster than volumes increased was a 9% year-over-year decline in quarterly EBITDAX and a 13% decline in year-over-year quarterly cash flow. EBITDAX for the fourth quarter of '08 was $192 million and cash flow for the fourth quarter of '08 was $165 million. Net income for the fourth quarter void by hedging derivative mark-to-market gains was $94 million, up 173% from last year's fourth quarter. Now earnings calculated as analysts typically do, which eliminates these type of nonrecurring and noncash items, was $52 million or $0.33 per fully diluted share. That's down 19% from the fourth quarter of last year. Cash flow for the fourth quarter per fully diluted share was $1.05, down 15% from last year.

These figures compare favorably to analyst consensus estimates of $0.22 for earnings and $1.03 for cash flow. Even though 2009 is expected to be a year of significantly lower oil and gas service costs, Range began to see real improvement in our direct operating cost in mid 2008 and the fourth quarter of 2008 was a continuation of this positive trend. Direct operating unit cost, including work-overs, for the fourth quarter was $0.94. Now this compares to $1.00 in the third quarter of '08 and $1.05 in the second quarter of '08. In fact, even though production has increased 20% year-over-year, actual direct operating expense for the fourth quarter of $35.7 million is the lowest since the first quarter of 2008. The reduction in direct operating expense may be attributed to fewer work-overs, lower water hauling and disposal costs, and reductions in general well servicing costs. My compliments to the Range Southwest Division, which is leading the charge in this cost reduction effort.

It's anticipated that further reductions in direct operating unit cost are possible as we enter '09, with direct operating unit costs in the mid $0.90 range expected. Working through the rest of the cost structure for the fourth quarter, G&A unit costs, excluding noncash stock compensation expense, was $0.53 per mcfe. That's down $0.01 from last quarter, but up $0.07 from the fourth quarter of last year. Essentially all of the G&A unit cost increase is attributable to our Marcellus Shale expansion. Some of the more significant G&A expense increases are from additional staff, employee relocation, office rent and even supplies. Unlike growth through acquisitions, establishing a major new shale play in a province without the required local expertise is not only a costly proposition, but the expense must be incurred prior to commencing large scale production.

I'm afraid it's going to take sometime to grow into these G&A expenses associated with our build out of the Marcellus Shale, but as I said before, we will gladly trade $0.10 of higher G&A unit cost for a $1.00 or more in lower finding and development cost. And we expect G&A expense to remain in that $0.55 to $0.59 range in '09. Exploration expense, excluding noncash stock compensation, came in well under guidance at $11.5 million for the quarter. That's due to lower seismic and dry hole expenses. Future 2009 quarters should see exploration expense in the $15 million to $17 million range. This is approximately one-third lower than 2008 and that's due to our lower capital budget in '09. Appearing for the first time on the income statement, on the line below exploration expense, is a new expense line item labeled abandonment and impairment of unproved properties.

These expenses formerly were combined with DD&A expense and have now been reclassified to a line item to improve statement clarity. Like most companies with significant acreage positions, Range's 3 million plus acre position represents a large asset in terms of both dollars and physical size. So periodically, undrilled acreage in areas that we deem non-prospective is allowed to expire or acreage may become impaired due to poor drilling results, the economic environment or surface use and title issues. Now during the fourth quarter of '08 Range recorded a $36.6 million noncash charge for acreage that was expiring or will expire in the near future that we do not intend to drill. The bulk of this acreage was in the non-core portion of the Barnett Shale and, to a lesser extent, Old-Trenton Black River and shallow tight gas sand Appalachian acreage.

Now while this noncash expense item will vary from quarter to quarter, we anticipate that we will be expensing approximately $5 million to $8 million per quarter in the future, depending on our drilling plans. Now the DD&A rate per mcfe for the fourth quarter of '08 was $2.18 compared to $2.11 in the fourth quarter of '07. Now the fourth quarter of each year that's when we reset our DD&A rate based upon the new year-end reserve report. And based on this year's reset, our DD&A rate per mcfe going forward into '09 is expected to be $2.20. This $2.20 figure includes $2.05 per mcfe for depletion and $0.15 per mcfe for depreciation and amortization of our other assets. The relatively small $0.15 increase in our core depletion rate, following one of the most high cost years in our business, is a very positive sign. It's also a good sign that the depletion rate didn't decline due to a large write-down in the carrying value of our proved reserves.

Besides having no impairment on our proved properties, as we have no goodwill on our books, we also had no goodwill write-offs. Interest expense for the fourth quarter of '08 was just over $27 million or $0.74 per mcfe. This compares to $0.68 per mcfe last year. Now the increase stems from the decision earlier in '08 to refinance short-term floating rate bank debt with higher rate fixed rate -- with higher rate ten year subordinated notes and also higher aggregate debt levels. Now interest expense per mcfe going forward should remain relatively constant. Those of you that pay attention to our income tax expense lines may notice that Range paid $4.3 million in cash income taxes during '08. Approximately one-third of this amount was Federal Income Tax, which we elected to pay in order to preserve some of our NOL carryforward slated to expire in 2012.

Our $159 million NOL carryforward is a valuable asset and by capitalizing some of our current year intangible drilling cost deductions for use in future years, we are able to utilize some of the NOL before it expires. The remainder of the cash taxes paid were mostly Virginia state taxes incurred in our operations there. Our Virginia operations are very low cost and also generate significant royalty income. When combined with last year's high natural gas prices, 2008 taxable income was generated there in excess of our deductions. Our effective tax rate remains 37% and we expect cash taxes in '09 to be between $3 million and $4 million, of which about $500,000 will be at the Federal level and the remainder at the state level. We added additional 2009 hedges to our position such that we now have approximately 81% of our gas production hedged in 2009 at a floor price of $7.62 per Mmbtu.

The bulk of the new hedges are for the second and third quarters of '09, which is where we saw the greatest potential for price weakness. Specific price and volume hedging information may be found on the press release and also Range's website. In summary we posted record revenue production and cash flow in '08 without burdening our balance sheet or compromising our low cost structure through ill timed high priced acquisitions. We also increased and strengthened our bank credit facility, preserving our access to over $0.5 billion in committed credit capacity. We have a running start to lower direct operating expenses in '09, thanks to another consecutive quarter of declining direct operating costs. From a macroeconomic perspective, while '09 is shaping up to be a challenging year, Range is positioned for a successful 2009, thanks to our low cost structure, strong hedge cash flow, attractive high rate of return projects in our core areas, and over $0.5 billion of available liquidity. With that, John, I will turn the mick back to you.

Thanks, Roger. I will now turn the call over to Jeff to review our operations and drilling results. Jeffrey?

Thanks, John. I'll begin by reviewing production. For the fourth quarter production averaged 403 million per day, a 17% increase over the fourth quarter of 2007. This represents the highest quarterly production rate in the Company's history and the 24th consecutive quarter of sequential production growth. Let's now review our three key projects. First I'll start with the Marcellus Shale on the Appalachian basin. The first processing plant and refrigeration plant came online last October and the capacity of the plant is 30 million per day. The second plant, a cryogenic plant, is on schedule and is planned to come online in early April. It will add an additional 30 million per day. In total, we anticipate having 180 million per day of processing capacity by late this year or early next year.

Range is on track to exit 2009 with Marcellus production at 80 million to 100 million per day net. We plan on accomplishing that with the three drilling rigs that we have now and exiting the year with six drilling rigs. The fact that we believe we can reach 80 million to 100 million per day net and only have to run so few rigs, speaks to the excellent quality of the wells that we are drilling and anticipate to drilling this year. The IPs for the last 13 wells tied into the plant averaged 6.9 million per day. Our latest well IP'd for 10.3 million per day. That's excellent for any shale play, particularly when you consider that these wells cost, will cost $3 million to $4 million and the gas sales for premium to NYMEX, not a $1.00 to $2.00 deduct like some other areas. We believe that the Marcellus Shale has excellent economics.

We currently are estimating reserves per well to average three to four Bcfe in the areas that we are drilling and the cost of drilling complete in a development mode to be $3 million to $4 million per well. Assuming the midpoint of both ranges and $7.00 per Mcf NYMEX gas price, the rate of return is 75% and the find and development cost is $1.16. At $5 per Mcf NYMEX flat forever, the rate of return is 46%. Assuming the same reserves and cost, NYMEX could drop to $3.25 per Mcf and these wells would still have a 20% rate of return. Our acreage position in the Marcellus fairway is nearly 900,000 net acres. This acreage was acquired at an average cost of about $500 per acre. The 900,000 acres equates to more than 15 to 22 Tcfe of net un-risk resource potential. Of that, 10 to 15 Tcf are located in the southwest part of the play, with the remainder in the northeast. We just announced two vertical wells in the northeast that tested at 24 hour rates of 6.3 and 2.3 million per day.

The 6.3 million per day is the highest reported 24 hour IP rate from any vertical well in the Marcellus play to date. Range also holds the record for the highest rate horizontal well in the play, too, which is 24.5 million per day. In addition to pursuing the Marcellus Shale, we are studying the Utica, Burkett, Middlesex, Genesee and [Ryan Creek] Shales. There is good potential for all these horizons on our existing acreage in the Appalachian Basin. The perspective areas of these unexploited shales targets largely occur within Range's core Marcellus acreage positions, thus allowing for stack pay opportunities and operational efficiencies in resource development. Range owns a total of 2.7 million gross acres or 2.3 million net of leasehold in the Appalachian Basin. Another very impactful low risk project for us in the Basin is our Nora area located in Virginia.

There is significant upside to all three horizons in Nora, CBM, tight gas sands and the Huron Shale. Range continues to drill successful CBM and tight gas sand wells in this field and has over 2,150 producing wells here. F&D costs net to Range continue to be around $1.00 per Mcf, which is among the lowest in the country. In addition, these wells produce very little water and have low lifting cost. Given its location in the Basin, these wells also receive a premium to NYMEX. This in combination with low F&D and low LOE, results in a very good rate of return of about 60% at a $7.00 per Mcf NYMEX gas price. At $5.00 the rate of return is 33%. Given a large number of wells which can be drilled in current spacing and assuming successful down spacing, there are approximately 6,000 wells left to drill. The latest development in Nora is horizontal drilling in the Huron Shale.

We know that the Huron Shale has good thickness and gas content across our acreage because we already have 107 producing vertical Huron Shale wells on it. We began drilling horizontally to verify that horizontal drilling is an effective way to economically develop these reserves. So far we are seven for seven. These seven wells averaged an initial peak 24 hour rate of 1.1 million per day to sales, which is very good. We have also drilled and completed two more, which should be turned to sales soon. This has the potential of about 1.5 Tcf of net gas reserves to Range. The next idea we will be testing at Nora is horizontal development in the Berea sandstone, which we believe has excellent potential on our acreage as well. Our first well was successful and came online at 1.5 million per day. Our second horizontal Berea well has been drilled and completed and is currently being tested. We should have a rate by the end of this week.

Next project I want to discuss is the Barnett Shale play in the Fort Worth Basin. Range currently has about 96,000 net acres in the Barnett Shale play. 42,000 net acres are in Tarrant, Johnson, Denton, eastern Parker, eastern Hood, northwest Ellis and southwest Dallas counties. This is the core part of the play and we still have over 1,000 locations to drill in these areas. That assumes 500-foot spacing, which equates to about 40-acre spacing. It also assumes 50% of the acreage is developed on 250-foot spacing. This represents 1.6 Tcf of net un-risk unbooked upside in the core proven part of the Barnett. Currently we have five rigs running in the Barnett. In this part of the Barnett, our wells are averaging about three Bcf and costs about $2.6 million. At $7.00 NYMEX this generates close to a 70% rate of return. At a $5.00 flat gas price forever the rate of return is 32%. I want to take a few minutes now and discuss Range's portfolio of properties.

Range has a great portfolio of properties led by the three projects that I have just described, the Marcellus Shale, Nora and the Barnett Shale. Approximately 90% of our 2009 budget will be spent in these three areas. This portfolio has resulted in Range consistently delivering top tier organic production and reserve growth with one of the lowest cost structures in the business. According to Bank of America's research, considering all-in cost, which includes F&D, LOE, G&A, interest expense and basin differentials, Range has the lowest or second largest cost structure of the group of companies that they cover for the last four years in a row., This is a direct result of our simple strategy of strong organic growth at top quartile cost structure or better and, in addition, consistently building and high-grading our inventory, coupled with one of the best teams in the industry.

Range has more upside today and lower risk upside than at any time in the Company's history. Today we have the opportunity to grow the Company more than tenfold, primarily from the Marcellus Shale, Nora and the Barnett Shale. Contrast that with Range's position five years ago, when the upside was less than double the base. Five years ago one-third of Range's production came from the Gulf of Mexico. Since then we sold the offshore properties, sold marginal low rate wells in Big Lake and Mill Stream fields in West Texas, sold high cost, low rate production in East Texas, and divested of Austin Chalk properties in Texas. We generated the modern Marcellus ID in 2004, acquired our initial interest in Nora at the end of 2004, and entered the Barnett Shale play in 2006. We have continued to grow and expand all three plays through new and innovative ideas that have resulted in the great positions and opportunities that we have today.

We believe our excellent organic growth, combined with an excellent cost structure, coupled with an upside ten times our base will result in creating strong shareholder returns over time. Back to you, John.

Thanks, Jeff. It's a terrific update. Now let's turn to 2009. Looking to 2009, it's obviously going to be both challenging and an exciting year for Range. Obviously the macroeconomic climate and the low commodity prices will be challenging. We are extremely excited about our opportunities. Regarding the Marcellus Shale play, our goal in 2009 is to ramp up development by increasing our drilling and tripling our production. In the fourth quarter of last year we were able to move from the R&D phase to the initial development phase. The first phase of the infrastructure was complete in October and we were able to increase production to 30 million a day net by year-end. In 2009 we are increasing our drilling activity and anticipate exiting the year 80 million to 100 million a day net.

In addition, we will focus on continuing to bring down our well cost, as we bring on our new fit-for-purpose drilling rigs. The good news is that we are off to a great start. At Jeff mentioned, our drilling results continue to exceed our expectations, as our last horizontal well IP'd for over 10 million a day and we drilled a vertical well in the northeast portion of Pennsylvania that IP's for over 6 million a day. In addition, the second phase of the infrastructure is proceeding as planned as the initial cryogenic processing plant should be up and running by early April. MarkWest, our infrastructure partner, continues to perform well and the recent announcement where they brought in an equity partner with $200 million of capital to specifically fund their Marcellus midstream operations, is great news for Range and its shareholders.

Regarding the Marcellus Shale play, we have discovered what many believe is a giant natural gas field. When you look back in history, there are only a handful of companies of Range's size that have discovered and developed fields of this potential magnitude. In 2008 we not only moved from the R&D phase to the development phase, but we captured a lot of the resource potential by increasing our acreage position by roughly 50% to nearly 900,000 acres in the fairway of the play. This is tremendous for Range and its shareholders. To put our 900,000 net acres in perspective, the core of the Barnett Shale play is a little more than 2 million net acres and the largest acreage position in the core held by any single company is 650,000 net acres held by Devon Energy, a $20 billion market cap company. XTO and Chesapeake together own 473,000 net acres in the core of the Barnett. XTO's market cap is $18 billion, while Chesapeake's market cap is approximately $10 billion.

The important thing that our shareholders should focus on is the potential per share impact that the Marcellus Shale play can have on Range. We are not a large independent like Devon, XTO or Chesapeake, who on average have roughly four times as many shares outstanding as compared to Range. Said a different way, our 900,000 net acre position will have roughly four times the impact on Range, on Range's per share value versus the three companies discussed above. This is why we say at Range we care more about our NAV per share versus our market capitalization. If we achieve 100 million a day of net Marcellus production by year-end 2009, the three larger companies would have to be at a rate of 400 million a day to have the same per share impact. To the extent that they have sold off or own less than 100% working interest in their leases, then they would have to produce an even greater amount.

While we have great respect for the three larger companies mentioned above, the point I'm trying to make is it's not about aggregate size or aggregate growth, it's about size and growth per share. In 2008 Range grew its production reserves per share on a debt adjusted basis by greater than 10% and at low cost. Since 2004 we have grown in production and reserves per share on a debt adjusted basis at a compound annual growth rate of more than 10% per year. At Range that's what we are keenly focused on. It's about increasing NAV per share each year, not having the largest market cap, the most rigs in operation, or the highest aggregate production. Now I will get off the soap box and provide some of the details for 2009. As mentioned in the release, our current capital budget for 2009 is $700 million. Roughly 90% of the budget is attributable to the Barnett, Nora and the Marcellus Shale play.

We currently anticipate that 77% of the budget will be used to drill 315 net wells, while the remaining $160 million will be used for acreage seismic and pipeline infrastructure. We are targeting a 10% production growth target for the year. Depending on how the Marcellus wells hold up, the timing of the next phases of the Marcellus infrastructure, how fast service costs continue to decline in combination with the timing of drilling, the 10% production growth target has more upside than downside. It is our view that 2009 is not a year where we should push production growth to the high-end of the range, but focus on making sure we achieve very cost-effective growth. For the first quarter of 2009 we are looking for production to come in at 408 million to 412 million a day. The midpoint represents an 11% production growth versus the prior year and if successful will represent our 25th consecutive quarter of sequential production growth.

As Roger mentioned, we are looking for operating cost to be in the mid $0.90 range for the first quarter, which will be lower than the first quarter of 2008. With regard to drilling rigs in operation, we have fixed 15 rigs running today. This compares with 34 rigs in operation this time last year. Importantly, our first fit-for-purpose Marcellus Shale rig will be delivered to -- has been delivered to Appalachia and is now on location and is being rigged up. We anticipate spudding our first well with this rig within the next few days. The second fit-for-purposes rig is scheduled to arrive in March, the third in August and the last three in the fourth quarter of 2009. We believe these new rigs will make a significant impact on reducing drill time and cost. One of our objectives for 2009 is to continue to drive down our well cost in the Marcellus. While equipment is important, people are even more important.

Our Marcellus team in Pittsburgh, home of the world champion Pittsburgh Steelers, now numbers 108 people versus 63 this time last year. We continue to add many high quality people to this team and I'm extremely pleased with what they've accomplished. Better yet, I'm excited about their potential as we have some of the best shale expertise in the business working each and every day on this play exclusively for Range. Getting back to the capital budget, we cut the budget to $700 million in an effort to keep spending in-line with cash flow. Given our excellent liquidity position, which Roger discussed, we are in a great position to capture unique opportunities in core areas that might avail themselves this year. Given the high degree of operational control, we will and will remain flexible as to the capital budget. The good news is that at $5.00 flat NYMEX gas prices, our drilling projects in the Marcellus, Nora and Barnett all generate over a 30% rate of return.

I'm obviously delighted that 81% of our 2009 gas production is hedged at an average floor price of $7.62 per McF. While we accomplished a lot in 2008, I believe the majority of our efforts will benefit 2009 and beyond. As you heard from Jeff, we now have projects in our drilling inventory and emerging plays that have 20 to 28 Tcf of net un-risk resource potential. This equates to eight to ten times our existing proved reserves. For example, we are now starting to unlock the upside of the Nora area. Beside the bread and butter CBM drilling, we are now accelerating the tide gas and shale gas horizontal potential of this 300,000-acre field. In the Barnett, we now have over 1,000 high quality drilling locations in core of the play. In western Oklahoma we have identified a high quality play in the St. Louis formation. Lastly, in our Marcellus Shale play in Appalachia, we have made enormous progress.

From discovering the play with our first vertical well in 2004, that came in at roughly 800 Mcf a day, to today where our last 13 horizontal wells have had initial production rates of 6.9 million a day, we have made incredible headway. In summary, we are in a superb position to add materially to our NAV per share in 2009 and over the next several years and are keenly focused on delivering. Finally, I would like to publicly congratulate and thank our talented team of roughly 850 employees for a job exceedingly well done in 2008. We have set the bar high for 2009, but I'm confident that with the talent, dedication and passion of the Range team, we will meet or exceed our goals for the year. With that, operator, why don't we turn the call open for questions?

(Operator Instructions). Our first question comes from the line of Tom Gardner of Simmons & Company. Please proceed with your question.

Hi, guys.

Hello, Tom.

With respect to your production growth estimates for '09 of 10%, can you walk us through area by area what you are actually thinking, what your thoughts are on those areas?

Let me just talk about it overall. Like we talked about 90% of our capital is going into the Marcellus, the Barnett or Nora. And we expect to get good growth or great growth out of all those areas. That being said, we've got a lot of tight gas sand production in Appalachian. We are not going to be drilling any wells, very little drilling out in the Permian Basin and all the other areas. You are coupling the decline from the base production in those areas, which is relatively low, with the growth that we have. So I think given that even out of the $700 million, a lot of that money is being directed into leasehold and seismic and pipelines and facilities, given the amount of drilling work we are doing. 10% growth is great. If the gas prices rebound next year, like I expect that they will, we really have the opportunity to ramp up and get significant growth really for years to come out of those key projects.

Did I hear you mentioned 16% base decline Company-wide earlier?

Well, we've said that before. If you look at the first year declines sort of in aggregate for the Company, that would be the base decline and then it flattens going out farther.

Okay. And you mentioned with regard to your asset sales, your planned asset sales or those that you are considering, are you talking about a sizeable package and where might the these properties be located?

Tom, this John. We currently formally have on the market our Fuhrman-Mascho property out in West Texas, which is an oil property, shallow oil property, but it has tremendous upside in terms of the (inaudible) commission just approved five acre spacing infill wells and also it has got some terrific water flood and tertiary opportunities. And over the years we've had a number of companies approach us with want to know if we wanted to sell those properties. And our thought was, well, to be honest with you I wish we would have sold it or put it up for sale a year ago. But given the opportunities we see in the other three areas, we just felt it made sense just to go ahead and put the property up for sale and see what we can fetch for it. So that's happening. We should know something within the next five or six weeks.

Obviously, not a great time to sell it, but again it has enormous upside so it might be one of those things that if they can give us a little credit for that we will go ahead and dispose of that and take those funds to capture more opportunities in the other areas that we operate that we think we can be make, quite frankly, higher rates of return. So that's the real strategy. If we don't get a decent price for it, we will just keep it and operate it and look to sell it at a later time when prices rebound and when the capital markets open. So we've got that property for sale. Then we've got some other assets that we've been talking to people about on and off. And quite frankly, those are smaller things and it all comes down to, I think, in each case the buyers really want to buy them and we've given them kind of numbers that we are willing to sell them at. The question is can they get financing for them and in some cases these are below $50 million, so it's in the small areas, I mean the small range.

And it is just, as you know, it's really tough financing right now. So again the way I kind of look at it is a little bit simple, like we kind of look at everything here, is that we have a kind of a little buffet of assets that we will consider selling and from time to time if other companies can come up with a number that we can support and it funds what we are doing into other areas, we will go ahead and let them go. If not, we will keep them and -- because you know most cases, just like Fuhrman, their pretty low declining properties. But as Jeff mentioned, I think the key really is, when it comes to these asset sales, is what are you really trying to accomplish as a company. And we've made the decision many years ago, again, that we don't care how big we are we just care about what the NAV is and what the stock price is. And at the bottom -- at the end of the day, to the extent that we can sell Fuhrman or anything else and then reallocate that capital into these, what we think are higher growth and higher rate of return projects, we think it makes incredibly good sense for us and our shareholders.

Well, thanks, guys, look forward to seeing you next week.

Thanks.

Our next question comes from the line of David Tameron with Wachovia Securities. Please proceed with your question.

Thanks, afternoon everyone. Jeff, can you talk a little bit about northeast, talk about where you drilled the vertical, differences you are seeing there versus some of the stuff you drilled down the horizontal area?

Well, yes, as we have -- when we started back in the play back in 2004 we identified multiple areas that we liked and that's where we focused our acreage. Across those acreage positions we've started in each of them by drilling vertical wells to test and gather information and to learn. And the area we started, obviously, first in was down in the southwest and since we started there first we've drilled horizontal wells that are faster and we've ramped up production faster. But we've -- we like the results that we see in other areas, particularly the northeast. We announced a well just today over 6 million per day, which is the highest rate vertical well that anybody has had to date.

Again, I don't want anybody to forget our 24.5 million day horizontal well either, because we are awful proud of that one. But what it shows is is that we have got, although we've got 550,000 acres in the southwest, don't forget we've got 350,000 acres in the northeast. We've confirmed that -- and we've got multiple delineation of wells on that acreage and some of them are pretty spectacular and, of course, Cabot has had good success up in the northeast and Chesapeake [strode] a good well up there now. We have good acreage position scattered across both plays and just a tremendous upside, so we are real excited by what we seen so far. This year, primarily, we are focused on driving up production. A lot of that's going to be in the southwest. Next year you will see us continue to drive production up there, but also start to do a lot of drilling in the northeast as well.

All right. What type of lease commitments do you have in the northeast for 2009?

We are in, we are in good shape. We are not really drilling right now to total acreage, although we are cognizant of that. We are lucky enough, again, our roots started in the Appalachian Basin. So we had acreage positions in some of those key areas to start with and, of course, we have added to it. Fortunately we are in stack pay areas. Some of those leases are already held by production from shallower horizons that have produced there historically or deeper horizons, in some cases, that have produced historically and we have got good term on our leases, so we are really focused on drilling the best rate of return wells that we can, driving up production, delineating our position and holding acreage. It's a combination of all those things.

Okay. Then one more question on Appalachian and I will let somebody else jump on. Can you guys talk about severance tax that float around in the budget that was recently submitted, I guess it was a couple weeks back?

Yes, just to give everybody kind of a background. One of the unique things about Pennsylvania is it does not have an oil and gas severance tax currently. It does have a state income tax and there is plenty of other taxes in Pennsylvania, don't get me wrong. But it currently does not have a oil and gas severance tax. With the shortfall in revenues in the state, the governor as well as some of the other legislators have discussed publicly the idea of instituting a severance tax. We've had, we and the rest of the Marcellus Shale committee have had extensive discussions with the governor and his staff, as well as some of the key legislative people in the state, not to try to in ways try to swing one way or the other, but just give them the facts in terms of what Texas and Oklahoma, Arkansas and some of the other states have done with regards to some of these shale plays.

And it's one of those things, it's interesting is the more you tax it early on, the longer it's going to take to ramp up and likewise. I think everybody understands, at least to a reasonable degree, the issues. The question is, what are they going to do and in that we don't know. We are not naive. We have historically run our models assuming a severance tax. So we think long-term there will be one. So it's something that is coming. It's something that we've been aware of. We are certainly receiving the benefit now of having no severance tax but that's kind of the, that's kind of the way we see it. And we will continue to monitor to the extent that we can be helpful and give, provide education, we will continue to do that.

What's the timing on the budget, just so we have that, do you know that?

It's not so much exactly time to the budget, but I would expect that they will discuss this and possibly vote on something this year no doubt.

All right. Thanks. Thanks for the color.

Our next question comes from the line of Joe Allman with JPMorgan. Please proceed with your question.

Thank you. Hi, everybody. I guess, Jeff, how about current production out of the Marcellus what are you guys running out of there right now?

Of course we've got the plant at 30 million per day capacity. We are actually running over that somewhat. We haven't been specific. We'll have the second piece on here, like I mentioned, adding another 30 million per day and we expect to, once that's on and, of course, there's always a little start up problem with every time you get a new plant in there you have got to work the bugs out, but we expect we will get production up pretty quick on that. I feel comfortable we will exit the year at 80 million to 100 million per day net, which again I think is phenomenal or it's excellent particularly considering the number of rigs we are running. We are not running 20 rigs to get that rate. We basically -- John went through the schedule of how we are going to ramp up. We currently have three rigs and come the end of the year we will have roughly six rigs.

In a way it's going to be a little bit like an offshore platform. I mean, we are going to go from let's say plus or minus 30 men a day, where we are today, to 60 men a day once we get the first cryogenic plant on in April. And so then we will max that out pretty quickly. We have got about 14 wells that we've already drilled that are not -- that in some cases tested and some cases not. They are just waiting on the next phase of infrastructure. So we will fill that out pretty quickly. As Jeff mentioned, like in anything that's mechanical, it will take a few weeks maybe in a month to sort all the kinks out. And then we will fill that up. The good news is our friends at MarkWest are doing a terrific job.

They are already -- while they are building the first cryogenic plant they are already also simultaneously building the second cryogenic plant, which is a 120 million a day plant, which is scheduled to come on either late this year or early in January of next year. So we are real pleased with that. I couldn't be happier. I give them an A plus. Frank and the guys at MarkWest have done a tremendous job. In our view we picked the right partner. They are spending that capital. We are not. And we are really focusing on ramping up the production, driving down our cost and really trying to focus on the highest rate of return projects for us. So from all that perspective it's going great.

But, when you think of it, we will be capacity constrained throughout the year, but by the end of the year we won't. So that's important. The other thing is as we drill in the northeast part where you don't need to be processed then we won't be constrained there. So the good news, as Jeff mentioned, 80 million to 100 million a day that looks good, That's a tripling of production and that's not an easy task, but we feel very good about that. And then by the end of this year, then we'll have the wind at our back in terms of the infrastructure and then we will be able to really ramp it up from there.

But, John, in the northeast though you do have to build some more infrastructure there, right, to develop that?

Yes, but it's, it's relatively easy stuff. It's just -- what it is it's just pure midstream pipelines and gathering. It's not a big 42 inch lines because we have got -- what's interesting in the Marcellus, which is different than a lot of the shale plays, is that the infrastructure is all related to midstream and that if you think of the Appalachian Basin and where this the bulk, at least what we think the bulk of the goodies of the Marcellus is going to be, I think it's either for the top six or five of the top seven largest pipelines in the U.S. run right through the middle of the play. So it's not a question of having to build huge 40, 36 and 42-inch lines to Carthage and whatnot, it's all about building anywhere from eight to ten to 14-inch lines to these big main lines that go up to such great places like New York City, Boston and Philadelphia. So that's already in place. We are working with MarkWest on some of those things. We are doing some of it ourselves, pipes going in the grounds, so all that's going according to Hoyle. We are very pleased on that.

I was just going to add, remember as you get into the northeast it's dry gas, so you don't need the processing, like John said, it's just really gathering and compression there so you don't have that piece.

That's helpful. And how about these two verticals wells you drilled, is there a rule of thumb in the Marcellus and like what kind of rates might you see on the horizontals based on the vertical rates you are seeing?

It's, it's probably too early to the say what the rule of thumb is. Obviously when 24 million a day well is pretty phenomenal and you look at what the vertical wells are down there, that's a tremendous increase. So you can get out large. I think it's too early to the come up with a rule of thumb, but I would say that with 6 million a day vertical well, I would expect that we will be drilling some pretty exciting horizontal wells up there as well.

I got you. How about the change in your production target from 15% to 20% to 10%, what's actually the change in activity that's causing you to bump that down?

Well, I mean, literally back in September and October when we first came out with that, cash flow -- oil and gas prices were significantly higher. So you are probably looking at cash flow back then of literally $900 million to maybe higher, close to $1 billion. So with that we just had a lot more drilling in there. So we have significantly less drilling and we think that's the prudent thing to do to live within cash flow. We think 10% growth, living within cash flow in this environment still allowing us money to continue to pick up acreage and do other things is great. And like John said, if prices recover next year we will have the wind in our sails and we will be off to the races.

Got you. And then I think Roger, you talked about inform NOLs, I missed that number and that was the year-end number, I think, you gave?

Yes, Joe, it's $159 million is our year-end NOL carryforward.

Okay. That's great. And then the acreage position you got in the Marcellus, the 900,000 acres, previously you used to talk about high-graded acreage. How much of that do you think is high-graded or how would you characterize that?

We've got about 1.4 million acres in the state, so that 900,000, roughly 900,000 was our high-graded number.

Okay. Got it. Okay. And then lastly, John, you talked about unique opportunities that you might pursue. What are you thinking about in particular there?

I can't tell you, but I can give you a little bit of color on it. If you sit back and think, I'm sure you have and I do it every night when I put my head on the pillow, but you just sit back and you think about what's really precious today is obviously capital to do things with and with the fact that the capital markets are, have gotten either shut down or they are extremely expensive. Really the thing that's just so critical this year is what you do with every dollar is really of incredibly importance. And the thing that I go back and forth on is where should we be focused. Clearly we need to grow our Company and continue to grow production reserves at low cost. That's our strategy. We will continue to do that. But that being said, I do think there is in this low price environment is that where you ought to be very sensitive -- for example, let's say that we ramp up and all of our Marcellus wells hold in there to a 24 million day and all the ones over 10 million a day all hold in there at numbers that are going to exceed the three or four Bcf that Jeff talked about.

If you think about that the question is then if you are going to hit the 100 million a day, you are going to max out that, should you take some of that extra capital you were going to spend on drilling and maybe do things like buy acreage in and around some of the sweet spots or if there is something incredibly cheap where somebody is in trouble do you take advantage of that? So my view of it is, and it's obviously changes from day-to-day and it's more art than science, is that '09 what you want to do is you want to, in my view, we want to hit double-digit production growth at sub $2.00 drilling cost. And then what we want to do is really be opportunistic and capture opportunities that are unique that we probably, that will probably go away once gas prices go back up. Because they will go back up. We all know that.

And try to capture some of those unique opportunities and the fact that a lot of these smaller companies -- I mean we are a small Company, but there's a lot of companies smaller than us, they are really going to be in tough shape this year in terms of capital and borrowing basis and everything else. And we've had a number come to us with different ideas. And we are going to be very careful about that just like we were last year. But I do think this is a year where you really need, where you will be able to do some things that will be very unique compared to the market two, three, four years from now. And so that's all I'm saying is just, just be opportunistic and take advantage of that. The -- we make this business so much harder than sometimes it really is. And if you really think about it, the biggest determinant in terms of acquisitions, in terms of rate of return is the commodity environment you are in when you buy the assets.

So if you buy assets when prices are low, the ability to make a good return on that is a lot higher, the probability, than when you buy assets that are in a $100.00 price environment of oil and $10.00 for gas. So that being said, to the extent that we have a few dollars left over to buy some unique things in core areas, and when I mean core areas these are things that are literally right next door to or directly associated with some of the major things we are doing. We will not be active at all in new plays outside of our core areas. Our sand boxes are plenty big enough right now to grow this Company, as we said, anywhere from eight to ten times or with just the assets we own, eight to ten times. So we are going to be -- while we are going to be opportunistic, we are also going to be very focused like we've been in the past.

That's very helpful. Thank you very much, everybody.

Our next question comes from the line of David Heikkinen with Tudor Pickering Holt & Company. Please proceed with your question.

Congratulations, guys, you are doing a great job. John, I never thought I would hear you say offshore platform again on a conference call so that made my day in a busy day. Just a lot of good questions so far. One thing that stuck out was the Hill County well rates and what you are seeing there, when you think about the 61 wells in the Barnett how many are down around Hill County now?

There's going to be very few. I mean those wells that we are going to be drilling, like I said, we are pulled into to the -- it's going to be Tarrant and Johnson and the really core properties that are proven. I am excited that the team drilled the best well, the industry's best well in Hill County to date and that looks like a strong well and it's performing well. But in this environment where you have really limited drilling dollars. we are going to focus on our highest rates of return best growth projects.

As you think about the splits of capital, kind of a couple hundred million dollars in the Marcellus and kind of 150 million, 180 million in the Barnett, is that about the right kind of order of magnitude or do you have the exact numbers for drilling capital?

You have got to spend about $150 million in drilling in the Barnett, about $200 million or more in the Marcellus, and about $75 million at Nora. So your big three is going to have about $450 million of drilling dollars. If you look at total budgets of infrastructure, land and things like that, that's going to be almost $600 million out of the $700 million coming to the big three.

A lot of that infrastructure and land is all going to be predominantly in the Appalachian Basin.

Okay. And then kind of final question, what are you thinking about 2010 hedges?

Interesting, very interesting question. My view of it is the cure for low prices, this is low prices, and so, David, if you can be so -- you were kind enough to ask the question so let me kind of expand it then I will get back and I'll answer your question. But let me just speak a little bit about at least what our view of the more on a macro basis what the market is doing and give you a little bit of insight because I think it's interesting. Is that, I think this year -- if you think about in '04, '05, '06, '07, everybody came out with capital budgets and production increases at the beginning of the year. What happened is all throughout the year people were increasing their budgets, doing acquisitions and increasing their production reserve estimates throughout the year. And that became very much the norm.

I mean we were a classic example of that. Little chicken John Pinkerton would come out with low double digit production growth and we ended up every year at 20% as the drilling did better and we did a few little acquisitions. I think 2009 is going to be the antithesis difference and I think what people are doing is reflective of that in that they are coming out with -- we were a perfect example. Our original capital budget was well over $1 billion when we were thinking early fourth quarter, late third quarter of last year. And then we've cut it, I think, three times since then. And we may cut it again. And we will continue to think about it. But if you look at just all the companies across the spectrum and there were like three yesterday and one today, everybody is cutting their budgets and they are going to be decreasing their production targets throughout the year.

And we are only into February. We've only got 15% of the year done. We have 85% of the year to go. So if you just extrapolate that out and without even gas prices coming down any further and I do think they will come down a little further before they jump back up. You are going to see people really cut back in terms of production growth. The other thing is is that the rig market is in a free fall. I can't even -- I've never seen it like this in my career. I've been at Range for 20 years and I've been in the business for over 30 years. I've never seen a free fall like this in terms of drilling rigs and services like I'm seeing today. The other thing is I've never seen companies more scared today than I've ever seen in my career and I think what it is is that a lot of companies are looking around their portfolios and essentially nothing is economic at today's prices.

So I think that being said, I think the industry is showing a lot of financial restraint and they are dropping rigs, people are paying money to get out of rig contracts. I've never seen that before. So when you look at it you are going to see a dramatic response on the supply side. The big question, and which, David, if you and I knew what the exact time of that we would be the richest guys on the planet earth, I don't know when and neither do you. The question is we know it's going to be fairly soon here. And in that regard I think, again, the cure for low prices is low prices. And because of that we are going to be very disciplined in the way we view the market. We are completely unhedged for 2010 and we are going to be very cautious in terms of pushing those hedges on until we see numbers that we think are reflective of the underlying value of those molecules of natural gas. If you look back in time there have been, just recently in this decade there was a time when gas price in the futures market hit $1.80 and two months later I think it was above $5.

So, again, you are going to see that and whether it's, when it happens I don't know when but it will happen. There's no doubt in my mind. It's just -- and it's even -- every piece of data I see as it comes across the tape and just talking to other CEOs and just seeing what's going on and in terms of both on the service side and the E&P side it's clear that it's going to happen. So that being said, we are going to hedge, we are just not going to hedge at these prices.

Okay. Thank you.

Our next question comes from the line of Michael Hall of Stifel Nicolaus. Please proceed with your question.

Thanks. Congrats, gentlemen. Kind of hammering on northeast Pennsylvania a little more. Can you provide any color as to what you saw in terms of reservoir characteristics or track barriers, thing along those lines, with your vertical wells as it relates kind of in the context of southwest, too, on a relative basis?

Yes, I mean, I appreciate the question and whatnot. We still are -- as you know, this play is still, there's a lot of acreage out there to be leased and we drilled more wells in the play than everybody else combined. We really view that as competitive advantage. We are still picking up leases. So we are going to be very, very quiet in terms of the questions you just asked.

Okay.

And so I will have to not answer it quite frankly. If you have got another question.

I figured that might have been the case. It's worth a try, though.

We can give you the generic answer, we saw things we really liked.

It looked like it.

And ended up with a good well.

Looking at the rigs you are bringing up into Pennsylvania, have you been able to kind of renegotiate on any of those terms and then what are the day rates you're carrying on those rigs?

I'm not going to give you specific numbers. What I will say when you look around it's a very, interesting year in terms of service costs like John said, people are are dropping rigs rapidly and then you are going to get into differences in areas of where you are in the country. Probably actually one of the more competitive areas is going to be the Appalachian Basin, because the economics are better there than in most places. Haynesville is drilling. A lot of activity in the Haynesville. And the Barnett, even though you still generate some good economics, given people trying to live within cash flow and oil and gas prices so down and having to cut back so far and you had so many rigs there. I'll give you an example of rig rates, I think at the peak in the Barnett, which was a year, year and a half ago, rigs went as high as $28,500 per day, today you can get rigs for under $10,000 a day.

So that shows you how dramatically they have dropped. But that's a less competitive area. Obviously the midcontinent and Rockies are probably less competitive. I don't want to get into specifically what we are paying for rigs in different areas. But I am excited that we have the built for purpose rigs up there. They are more designed for the type of application we need. They are really going to help us drive down our cost. That will get us in a true development mode once this first rig spuds and we start drilling and I expect that we are really going to post some great numbers by the end of the year. But I think the theme throughout the year in general is going to be the bad news is oil and gas prices are low, but sort of the offset to that somewhat is service costs are really coming down for everything from drilling rigs to fracking to steel and everything else.

The interesting thing, just to pile on what Jeff said, the one thing that's interesting is that if you look at the Barnett Shale for six straight years the rig count went up every single month. Every single month the rig count would be higher than it was the month before. When you look at it today it's less than half the rigs are working in the Barnett than there was six months ago. That is incredible. Especially given that the Barnett Shale is the largest gas field in the U.S. and Texas production would be down year-over-year if it wasn't for the Barnett. So that gives you some idea. The interesting thing in terms of how this affects the Marcellus is is that the equipment in the Barnett can be easily put on rail cars or moved to Appalachia. So we are going to benefit, I think we are going to benefit from pressure pumping to rigs and especially people.

One of the largest drilling contractors in the U.S. I saw him at a conference not too long ago and he mentioned that now he has people lining up at his door wanting to go move to Appalachian. That wasn't the case a year ago. So the good thing is I think we will see some slot factor in terms of this whole service cost mumbo jumbo as it moves to the -- in favor of the Appalachian. As Jeff said, when you are only paying an eighth royalty, when you are getting premium at NYMEX versus $1.00 to $2.00 difference to NYMEX, it sure makes those wells up in Appalachian a lot more economic on a relative basis. So you are going to see a lot of equipment, I think, move up to the Appalachia Basin and that is just unbelievably good news for the, not only for Range but the entire Marcellus Shale play in general.

And so in some respects the pull back in prices is going to have a really profound effect in terms of service infrastructure in the Marcellus. I think it's going to be one of the direct beneficiaries.

Thank you for that color. Finally, the asset sales are any asset sales assumed or production sales assumed in the current guidance of 10% growth or what do you think about that.

Yes, not a whole lot but on the other end of it when we put down a number, obviously we had some idea that we would be selling some stuff. If we do any material sales we will come back to you with a new production number. But again it all depends if we sell early in the year it will have a bigger impact than if we sell in the later in the year and all the other stuff that comes into those kind of things.

What's Fuhrman producing these days?

About 16 million per day equivalent.

Okay. Great. Thank you very much and congrats.

Our next question comes from the line of Biju Perincheril with Jefferies. Please proceed with your question.

Hi, good afternoon. Going back to the northeast hopefully you can answer that, the well that was 6 million cubic feet a day, was that a simple vertical well was in a single stage completion or was, did you try some of these the multistage completion that some competitors are trying up there?

Well, I will answer part of your question. Yes, it was a vertical well. But exactly how we completed it and what we pumped and all, like John said, for competitive reasons for right now we want to keep that tight. Obviously other people are coming up with recipes and formulas that's good. Atlas has drilled some very good vertical wells, as has Cabot and others. But we've invested a lot of time and capital and effort to get where we are, so until that acreage position is pretty locked up we will keep that tight. The other thing I hope you guys do appreciate is since we started this in Denver we've kept peeling back more and more layers of the onion, giving more and more information. So we are trying to be more and more transparent, but because of competitive leasing reasons we are going to have to keep some stuff tight.

Okay. And then on, in the southwest, Jeff, you mentioned you hoped to get to 3 million to 4 million per well completed costs. What is actual cost running now?

In -- they're obviously they are a little more than that. There's three easy ways I think we will get there maybe four. One is we still have science in the wells and although the trouble costs are coming down they are not zero. If you eliminate the science and trouble out of our more recent wells would be $3.2 million, $3.3 million. Obviously once you drill 100 or whatever the magic number is or horizontal wells or 150 or something, your trouble costs are going to approach zero and obviously we won't need the science. That being said, getting these built for, fit-for-purpose rigs in and then just being in a declining service cost environment, I'm comfortable our guys will get there or they may even breakthrough the low end in the southwest.

And then what's the sort of spud to completion time in the southwest now?

Spud to completion -- spud to, spud to spud on our best wells is about 20 days, 21 days, something like that. And then they will come back and complete the wells later on and that's a function of where the pipeline is and timing and a lot of other stuff. The fracs in some aspects aren't a whole lot different here than in the Barnett. Depending on how long the lateral is and how many stages you have, fracking may take three to five days or something like that.

Okay. And with the fit-for-purpose rigs, what do you think that number can go down to.

Again, to use an analogy of the Barnett, we've gotten as low as ten days per well, spud to PD or type thing. It is a little -- depending on where you are again it's a little more complex up there. You have coal strings and other things that you have to do. But I think you could, in time, maybe on well 200 or something, out of 6,000 or however many we end up drilling, you might approach ten or 12 days per well, something like that. So I know our guys listen to these calls so there's your challenge.

Just to pile on what Jeff said, what's interesting is what got us there, for example, in Hood County, right in the corner of Hood and Johnson County where we've had a fair amount of success at the Mitchell Ranch. I think our first well cost $3.6 million and took us over 30 days and we brought in a fit-for-purpose rig after, I think, wells number 16, 17, 18, we drilled them on a single pad sequentially and we drilled all three of those wells in 31 days and I think the costs were $1.6 million to $1.8 million each completed. I think that really, that recipe and that really holds true to any shale play, quite frankly, unless you are in maybe in the Haynes, the deeper part of the Haynesville that's way over pressured and has got a lot of mechanical issues and extra drill strings and stuff. If you think about the southwest PA it's not too much different in terms of both in terms of vertical depth and laterals that we are doing in Hood County, Texas.

So from that perspective having fit-for-purpose rigs that are smaller that can move around instead of being 20 18-wheeler loads to move them like these big rigs we've got now that come down to maybe 3 18-wheelers with no cranes that's a big cost savings in terms of just moving it from location to location. The other thing is one of the things that we think is really important is to really aggregate your acreage up and get big blocks of acreage, which is really hard to do in Appalachian because the acreage blocks that -- I think our average lease is 200 acres leased.

So to the extent that we've had 30 years, in some cases, to aggregate all these acres and we have got big yellow blocks of acreage to the extent that you can drill multiple wells from a single pad it really reduces your road cost, it really reduces your pipeline cost, it really reduces your myob cost on your drilling rig, that will save you an enormous amount of money and it all gets back to the efficiencies and whatnot and how you charter all this stuff out. Again those are some of the things that we are going to be really focused on during 2009. And that's how we are going to get the cost down. If you think about some of the numbers that Jeff has talked about, if it's $0.5 million per well that we can save and all the stuff that we've learned this year and next year we drill, I don't know how many wells, let's say it's a couple hundred, that's $100 million.

If we drill 100 wells next year that's $50 million. It's huge amounts of money. So that's why we are so focused in terms of getting the per well cost down. Because if you think about the size of the play, four years from now we are going to have a gazillion rigs up there running, so the extent that we can save $300 to $500 per location with a gazillion rigs and you've run that math, that's a gazillion dollars.

And just to add on to what John is saying, not only is it cheaper and these new rigs are actually going to have walkers and stoppers where you can move, literally move the rig in less than a day it will move itself in a matter of hours. Environmentally it's a better thing to do drilling off a pad, you are disturbing less land. It's better for the land owner, you are disturbing less of the land owners lands. There is a lot of other reasons to do that as well. It's economical the right thing to do, but for the land owner and the environment it's the right thing to do, too.

We are nearing the end of today's conference. We will go to Rehan Rashid of FBR Capital Markets for our final question.

Hi, Jeff, John, on the decline rates for let's just say your 24 million a day well, I know it's very early, but is it kind of tracking what you would have seen maybe less of an IP rate well?

Let me put it this way. I'll just be fairly straight forward. It is early, but a well like that could have reserves of eight to ten Bs or something like that. So when we talk about average reserves of three to four Bs, like John mentioned, when you are getting these wells that are 10 million or 10 million a day plus, obviously they are going to be better than that. So when you look at our wells in aggregate, so far in the Marcellus and our oldest well now has been on now for a pretty reasonable amount of time. Approaching it will be two years this August. And you plot those wells up versus the Barnett wells, they compare very favorably. So we are pleased with what we see so far.

Got it. And when do you reach a statistically significant number of wells that you can say, okay, I'm willing to address my EUR guidance in either direction? Is it 50 wells, is it 100 wells, 200 wells?

It's a combination of a number of wells and time. As soon as you get enough time to really see those curves and at the end of the day it's going to be like all plays, where you are makes a big difference, whether you are in the high quality core best parts of the play or whether you are way out on the fringe. So you are not going to be able to apply one number across the entire play. There is going to be good areas in there and poor areas. Obviously we have drilled some excellent areas. But we will with more history and more time and more wells refine those numbers. I think our numbers so far, I think the range of costs of $3 million to $4 million per day for three to four Bcf is certainly I feel, still feel comfortable with those numbers. When you consider that those kind of numbers the midpoint of the play give you finding cost of just a little over $1.00 and rates of return of -- that are pretty phenomenal regardless of what gas price you use, I feel really good about that.

The other thing we are learning in the play so far is its not just Range's wells, but you are getting other people's wells that sort of confirm and validate the play as well. Going back to the southwest, Range's had great results but that play, that area, that 550,000 acres in a lot of ways has been somewhat de-risked by drilling from Atlas and Chesapeake and Equitable and CNX and Range and a lot of people that have had good results. It says a lot about our acreage position in that area. In fact, I can't think of any bad results in there so far. If you go up to the northeast there's been also not just Range drilling and announcing good wells, but Cabot has announced good wells up there. Chesapeake has announced good wells up there and there's others as well. Southwest will be drilling, there's a lot of name brand companies up there and throughout the play.

And Rodney is keying me in on some of the areas that haven't worked so well and some of the other companies. I only like to talk positively about Range and our brethren, but you guys know what wells haven't worked up there and, I think, where they are. We've put maps out like that and talked about it in some of the conferences.

Got it. What about the kind of BTU content as you are kind of moving in and around different areas? Is that holding at pretty high rate that you are initially seeing or are there some changes there?

The BTU -- it's similar to the Barnett, you are going to get as you go east on the eastern side your dry gas is about 1,000 BTU and as you go farther west it gets rich and the rich gas area is 1300 or 1400 BTUs and if you just continually to go west eventually way into Ohio somewhere you probably get oily, just like in the Barnett if you go way west eventually you get oily. You will see that Range throughout the play. And there are good wells in the dry areas and there's good wells in the high BTU areas.

And the average that we kind of heard this morning, 6.9, that is a kind of BTU adjusted number, right?

That -- no, that's adjusted for liquids. That's 1 million cubic feet per day equivalent. That's not BTU adjusted. Obviously, once you process the gas you produce the gas -- I will just talk about the west gas here, as you produce the gas and some of them will produce some liquid initially so you get the gas and then you run that gas through the plant and you produce liquids from the plant and then the residue gas in the rich areas, even after processing, might be 1150 to 1200 and then we get paid that BTU uplift. So in the wet areas you will get the gas plus the BTU uplift plus the liquids. So really it helps the economics and enhances it and the dry gas rates basically dry gas it's 1,000 BTU, you get paid what you get paid. But there's good wells in both areas.

And one last question, on the processing capacity front you are adding something early or ten as well, right?

We are adding a big cryo plant that will either be end of this year or early '10, right, that will really significantly increase capacity. And the guys are doing a very good job of staying ahead of the drilling machine. We want to make sure that we are drilling the highest rates of return, best quality wells, like I said, at the same time delineating our acreage, but the pipelines and processing and takeaway are staying ahead of the drilling machine. So we got a good team working in a very integrated way to make sure we have all those pieces in place to continue to drive more success.

Thank you.

The one thing just that's been surprising with when we first put the infrastructure plan, we used kind of that three to four BCF and we used the kind of the IPs associated with that, so what happened was we hit some of these bigger wells in terms of just compression and whatnot it really, we had a really high-graded problem there. And so in some of these cases we tested wells and we just shut them in and we are waiting for the infrastructure to catch up a little bit.

But again, one of the really neat things about the Marcellus is is that, and there's been a lot of written on it, is that it's really just amid stream issue and then as the play really develops out, there is no place on the planet earth you would rather have gas than the Marcellus Shale play because it it going -- if it really works in a big way, some of the basis differentials you've seen in the Rockies is really going to affect other areas because this play is going to have such a monumental impact if -- not so much us but what you hear about what other people think the play is going to be. It is exactly where you want to be selling BTUs of gas. Two-thirds of the population of the United States lives within a 350 mile radius of Pittsburgh, Pennsylvania. So home of the world super bowl Pittsburgh Steelers. So it's a great place -- .

Six time camp, I might add, being that I grew up there.

It's really a great place to sell gas. And what's interesting its really neat to see some of the proposals we are seeing in terms of long-term gas infrastructure, some of the partnerships that people want to do with us in terms of long-term supply, in terms of electric supply and generation and whatnot, it's really cool. All that being said, we are keeping our head down, we are in the bunker. We just want to hit 100 million a day this year. We want to drive up, drive down our cost, drive up production. As Jeff has said, I think this is hopefully it's coming through loud and clear, we really feel like we de-risked the play to a large extent. A lot of you on the call obviously don't know what we know and therefore are going to risk what we say and that's appropriate.

But as we get to 30 million, as we get to the middle of the year we will be up more and as we get to the end of the year the 100 million, then if you just look and Southwestern is a perfect example, once they got to 100 million a day to where they are today, a lot of the risk is gone. And then it's just a question of just getting more rigs and more people and making the commitment and driving it up. And we are doing that. We've increased -- we've got 108 people, knowing Ray he's probably has got 120 people as of today because he hires people faster than I can approve them. And we've got more office space. We are making all the commitments that we need to really drive this play up to be a really big time gas play.

And again I can't say more about our people up there led by Ray Walker and Steve Rupert and John Applegath and the others we have up there, Matt Currie and the others. We have just got a really first class -- Dan Caulterman -- we've just got a -- and Greg Davis -- we have got a first class group of people up there that really know what they are doing and they are going to be driving the production up. And if they can do it, they will all be rich, just like we will because we are fully invested in Range.

Don't forget the famous Billy Z and I won't say who that is.

Just one more question, so on the cost, Jeff, I'm trying to remember numbers, my numbers but I think you used to mentioned that 3 million to 4 million and then when we go into development mode, sub three, as you kind of go out based on service infrastructure from where it is today and maybe not as dislocated as it could be the next few months, but some sort of average in between, where do you think could be a good number to settle it down to, two, two and a half or is that too aggressive.

I think once we get these all of our fit-for-purpose rigs in there and drill a few more wells, I think in the southwest part of the play we will be in that 3 million to 4 million slot and towards the low end. Like I said using the analogy of Hood County and John mentioned it again today, those wells are 1.6 million drill and complete in today and falling. You got to remember it's not an apples-to-apples because you got coal strings, you got some different things in PA that you have got to account for. But in time could they break 3 million and get to 2.5 million or something lower than that? Those are certainly possible. We have got a first class team up there and I think those guys will do wonderful things.

Okay. Thank you .

Ladies and gentlemen, this is the end of our electronic Q&A session. I would like to hand it back over to Mr. Pinkerton for closing remarks.

Well, we thank you all for joining us today. We have obviously run over and we appreciate you all that stayed with us. We had a lot of great questions. It's -- 2009 is going to be a really interesting year. We off to a great start. We've drilled some great wells.

Our production looks on track and we are going to behave ourselves in terms of our capital budget. We look forward to continuing to give you results in the Marcellus, as well as our other plays. I don't want to forget the other plays. What's made Range really is our portfolio of projects, the Barnett is important, Nora is important, but so is the production that helps support that and the men and women in those other divisions they do a terrific job as well. With that we will sign off and if anybody has any questions that we didn't answer, feel free to call any of us and we will be happy to answer those questions. Thanks again and we will see you after the first quarter.

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