Rodney L. Waller – Senior Vice President & Chief Compliance Officer John H. Pinkerton – Chairman of the Board & Chief Executive Officer Jeffrey L. Ventura – President, Chief Operating Officer & Director Roger S. Manny – Chief Financial Officer & Executive Vice President

Tom Gardner – Simmons & Co. David Tameron – Wachovia Capital Markets Joe Allman – J. P. Morgan David Heikkinen – Tudor Pickering & Co. Michael A. Hall – Stifel Nicolaus Biju Perincheril – Jefferies & Co. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.

Welcome to 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 risk 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. Rodney L. Waller: 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 year of sequential production growth with 24 consecutive quarters of sequential production growth. Drill bit finding cost for the year came in at $1.70 per MCFE and drill bill 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’ve 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’ve presented a summary of the non-GAAP numbers which correspond to the analyst models taking out certain non-cash 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 10K with the SEC this morning. It is available on the home page of our website or you can access it using the SEC 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 reconciliation 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’ll 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 & Gas Conference in New York on April 21st. Now, let me turn the call over to John. John H. Pinkerton: Before Roger reviews the financial results, I’ll review some of the key accomplishments for 2008. On a year-over-year basis, production rose 20% beating the high end of our guidance. Fourth quarter production averaged 303 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 is our peer group has achieved that particular goal. This is a vivid testimony to the quality in my opinion of our operating teams. At yearend 2008 proved reserves totaled 2.7 TCF a 19% increase over 2007. As Rodney mentioned reserve replacement from all sources was 405% including oil revisions. Our drilling program alone delivered 367% reserve replacement at a cost of about $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 crude 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 Appalachia. Next, at the end of the day we combined exceptional growth in production in reserves with low finding costs, that’s the hard part in our business, combing high growth with low costs. Again, this performance is attributable directly to the very talented technical teams that are with Range. In 2008 we completed $68 million of assets 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; and 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’re considering selling a few properties in 2009. We’ll only pull the trigger if we see reasonable prices, if not we’ll hold on to the properties and look to sell them later. When you look at 2008 I’m 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’ll turn the call over to Roger to review our financial results. Roger S. Manny: 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 hedged position up to approximately 81% of our anticipated ’09 gas production and that’s at a floor price of $7.62 an MMBtu. Third, we issued $250 million of 10 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 share acreage at very attractive prices. Fourth, we increased our liquidity by raising our committed bank credit facility from $900 million to $1,250,000,000 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. Net income calculated as analysts typically do which excludes asset sales 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, we please view the Range earnings new 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 improving oil and gas prices outpacing increases in operating costs. The average price received for our oil and gas sales this year including the hedges on those volumes increased by 7% from $8.03 a MCFE to $8.58 per MCFE. As John often reminds us and as he just mentioned, sometimes the best deals you do for the company are the ones that you do not do. By relying on steady drill bit growth, refraining from high price proved reserve acquisitions and by financing our unproved acreage purchases with common equity and 10 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 debt to cap ratio was 42% at the end of the year. That’s compared to 40% at the beginning of ’08. We ended the year with over $500 million 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 reliance upon any single bank. 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 credit facility borrowing base by running our yearend proved reserves using the current agent bank ’09 gas and oil price assumptions that start at $4.50 per MMBtu and $40 a barrel. The results 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’re in great shape. Direct operating expenses excluding non-cash 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 non-cash comp for the year was $0.49 per MCFE compared to $0.44 last year. Interest 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 non-cash total unit cost expense for ’08 was 8% higher than ’07. While cost increases are never welcome, we’re 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 costs. The bad news was a 21% decrease in well head 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 ’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. Our earnings calculated as analysts typically do which eliminates these types of non-recurring and non-cash 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 costs in mid 2008 and the fourth quarter of 2008 was a continuation of this positive trend. Direct operating unit costs including work overs for the fourth quarter was $0.94. Now, this compares to $1 in the third quarter of ’08 and $1.05 in the second quarter of ’08. In fact, even though production is 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 is anticipated that further reductions in direct operating unit costs 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 non-cash 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 costs increase is attributable to our Marcellus shale expansion. Some of the more significant G&A expense increases are from additional staff, employee relocation, office ramp and even supplies. Now, unlike growth through acquisitions, establishing a major new shale place 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 some time to grow in to these G&A expenses associated with the build out at the Marcellus shale but as I’ve said before, we’ll gladly trade $0.10 of higher G&A unit cost for $1 or more in lower finding and development costs. We expect G&A expense to remain in that $0.55 to $0.59 range in ’09. Exploration expense including non-cash 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 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 specific line item to improve statement clarity. Like most companies with significant acreage positions, Range’s three plus million acre position represents a large asset in terms of both dollars and physical size so periodically undrilled acreage and areas we deem non-perspective is allowed to expire or acreage may become impaired due to poor drilling results, the economic environment or surface use and title issues. During the fourth quarter of ’08 Range recorded a $36.6 million non-cash 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 full Trenton Black River and shallow tight gas sand Appalachian acreage. Now, while this non-cash expense item will vary from quarter-to-quarter we anticipate that we will be expensing approximately $5 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. In the fourth quarter of each year that’s when we reset our DD&A rate based upon the new yearend reserve report and based on this year’s reset out DD&A rate per MCFE going forward in to ’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 our large write down of 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 have 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. The increase stems from the decision earlier in ’08 to refinance short term floating rate bank debt with higher rate 10 year subordinated notes and also higher aggregate debt levels. 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 taxes which we elected to pay in order to preserve some of our NOL carry forward slated to expire in 2012. Our $159 million NOL carry forward is a valuable asset and by capitalizing some of our current year intangible drilling cost deductions for use in future years we’re able to utilize some of the NOL before it expires. Now, 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 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 price acquisitions. We also increased and strengthened our bank credit facility preserving our access to over $500 million 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’s position 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 $500 million of available liquidity. With that John, I’ll turn the mic back to you. John H. Pinkerton: I’ll now turn the call over to Jeff to review our operations and drilling results. Jeffrey L. Ventura: 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 its 24th consecutive quarter of sequential production growth. Let’s now review our three key projects. First, I’ll start with the Marcellus shale in the Appalachian basin. The first processing plant a 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 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 to 100 million per day net and only have to run so few rigs speaks to the excellent quality of the wells we’re drilling and anticipate to drill this year. The IPs for the last 13 wells tied in to the plant average 6.9 million per day. Our last well IP’d for 10.3 million per day. That’s excellent for any shale play particularly when you consider that these wells will cost $3 to $4 million and the gas sells for a premium to NYMEX not a $1 to $2 deduct like some other areas. We believe that the Marcellus shale has excellent economics. We currently are estimating reserves per well to average 3 to 4 BCFE in the areas that we’re drilling and the cost to drill and complete in a development mode will be between $3 and $4 million per well. Assuming the midpoint of both ranges, and $7 per MCF NYMEX gas price, the rate of return is 75% and the finding and development cost is $1.16. At $5 per MCF NYMEX flat forever the rate of return is 46%. Assuming the same reserves and costs 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 equate to more than 15 to 22 TCFE of net unrisk 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 rate 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’re studying the Utica, Burkett, Middlesex, Genesee and Rinestreet shales. There’s 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 in Virginia. There’s significant upside to all three horizons in Nora, CBM, tight gas sands and the Huron shale. Range continues to drill successful CMB 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 per MCF which is among the lowest in the country. In addition, these wells produce very little water and have low lifting cots. 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 per MCF NYMEX gas price. At $5 the rate of return is 33%. Given the 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 in 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’re seven for seven. These seven wells averaged an initially peak 24 hour rate of 1.1 million per day to sales which is very good. We’ve 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’ll 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 on line 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. The 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 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 540 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 unrisk, 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 3 BCF and cost about $2.6 million. At $7 NYMEX this generates close to a 70% rate of return. At a $5 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’ve 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 in reserve growth with one of the lowest cost structures in the business. According to Bank of America’s research considering all in costs which includes F&D, LOE, G&A, interest expense and basin differentials, Range has the lowest or second lowest cost structure of the group of companies 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 core tail 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 10 fold 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 Mills Strain 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 idea in 2004, acquired our initial interest in Nora at the end of 2004 and entered the Barnett shale play in 2006. We’ve continued to grow and expand all three plays through new and innovative ideas that have resulted in the great positions and opportunities we have today. We believe our excellent growth combined with an excellent cost structure coupled with an upside 20 times our base with result in creating strong shareholder returns over time. Back to you John. John H. Pinkerton: 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’re extremely excited about our opportunities and 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 completed 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 at 80 to 100 million a day net. In addition, we will focus on continuing to bring down our well costs as we bring on our new fit for purpose drilling rigs. The good news is that we’re off to a great start. As 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’d 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. Mark West, 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’re not a large independent like Devon, XTO and 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’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 yearend 2009 the three larger companies would have to be at a rate of 400 million per 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 about, the point I’m trying to make is that 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 dead adjusted basis by greater than 10% and at low cost. Since 2004 we have grown in production and reserves per share on a dead adjusted basis at a compounded annual growth rate of more than 10% year. At Range that is 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’ll get off the soapbox 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’re looking for production to come in at 408 to 412 million a day. The midpoint represents an 11% production growth versus the prior year and if successful will represent the 25th consecutive quarter of sequential production growth. As Roger mentioned, we’re looking for operating costs to be in the mid $0.90 for the first quarter which will be lower than the first quarter of 2008. With regard to drilling rigs in operation, we have 15 rigs running today. This compares with 34 rigs in operation this time last year. Importantly, our first fit for purpose Marcellus shale rig has been delivered to Appalachia and is now on location and being rigged up. We anticipate spudding our first well with this rig within the next few days. The second fit for purpose 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 costs. One of our objectives for 2009 is to continue to drive down our well costs in the Marcellus. While equipment is important people are even more important. Our Marcellus team in Pittsburg, home of the world champion Pittsburg Steelers now numbers 108 people versus 63 at 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 flat NYMEX gas prices, our drilling projects in the Marcellus, Nora and Barnett all generated 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 in emerging plays that have 20 to 28 TCF of nut unrisk resources potential. This equates to eight to 10 times our existing proved reserves. For example, we are now starting to unlock the upside of the Nora area. Besides the bread and butter CBM drilling we’re not accelerating the tie gas and shale gas horizontal potential of this 300,000 acre field. In the Barnet we now have over 1,000 high quality drilling locations in the core of the play. In western Oklahoma we’ve identified a high quality play in the St. Louis formation. Lastly, in our Marcellus shale play in Appalachia we’ve made enormous progress from discovering the play with our first vertical well in 2004 that came in at roughly 800 MCF today 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’d like to publically 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 over for questions.

(Operator Instructions) Your first question comes from Tom Gardner – Simmons & Co. Tom Gardner – Simmons & Co.: With respect to your production growth estimates for ’09 of 10% can you walk us through area-by-area what you’re actually thinking, what your thoughts are on those areas? Jeffrey L. Ventura: Let me just talk about it overall. Like we talked about 90% of our capital is going in to 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 Appalachia where we’re not going to be drilling any wells, very little drilling out in the Permian basin and then all the other areas. You’re coupling the decline from the base production in those areas which is relatively low with the growth that we have. So, I think that given even out of the $700 million a lot of that money is being directed in to leasehold, seismic, pipeline and facilities. Given the amount of drilling work we’re doing 10% growth is great. If 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. Tom Gardner – Simmons & Co.: Did I hear you mention 16% base decline companywide earlier? Jeffrey L. Ventura: We’ve said that before. If you look at the first year decline sort of in aggregate for the company that would be the base decline and then it flattens going out farther. Tom Gardner – Simmons & Co.: You mentioned with regard to your planned asset sales or those that you’re considering, are you talking about a sizeable package? And, where might these properties be located? John H. Pinkerton: We currently formally have on the market our Fuhrman-Mascho property out in West Texas which is a shallow oil property but it has tremendous upside in terms of the Railroad Commission just approved five acre spacing infield wells and also its got some terrific water flood and tertiary opportunities. Over the years we’ve had a number of companies approach us wanting to know if we wanted to sell those properties and our thought was – well, to be honest with you I wish we had sold it or put it up for sale a year ago. But, given the opportunities we see in the proposed three areas we just felt it made sense to go ahead and put the property up for sale and see what we can fetch for it. 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’ll 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 make quite frankly higher rates of return. That’s the real strategy. If we don’t get a decent price for it we’ll just keep it, operate it and look to selling it at a later time when prices rebound and when the capital markets open. So, we’ve got that property for sale and 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 wanted to buy them and we’ve given them kind of numbers that we’re willing to sell them at the question is can they get financing for them. In some cases these are below $50 million so it’s in the small range and 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 look at everything here, we have kind of a little buffet of assets that we’ll 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’re doing in other areas well go ahead and let them go, if not we’ll keep them. Because, most cases just like Fuhrman, they’re pretty low decline properties. But, as Jeff mentioned, I think the key really is when it comes to these assets sales, 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. At the end of the day to the extent that we can sell Fuhrman or anything else and then reallocate that capital in to what we think are higher growth or higher rate of return projects, we think it just makes incredibly good sense for us and our shareholders.

Your next question comes from David Tameron – Wachovia Capital Markets. David Tameron – Wachovia Capital Markets: Jeff, can you talk a little bit about Northeast? Talk about where you drilled the vertical, differences you’re seeing there versus some of the stuff you drilled down the horizontal area? Jeffrey L. Ventura: 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. The area we started obviously first in is down in the southwest. Since we started there first we’ve drilled horizontal wells there faster and we’ve ramped up production faster but we like the results that we see in other areas particularly in 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 anyone to forget our 24.5 million a day horizontal well a day either because we’re awful proud of that one. But, what it shows is that although we’ve got 50,000 acres in the Southwest, don’t forget that we’ve got 350,000 acres in the Northeast and we’ve got multiple delineation wells on that acreage and some of them are pretty spectacular and of course Cabot’s had good success up in the Northeast and Chesapeake has drilled a good well up there now. So, we’ve got good acreage positions scattered across both plays and just a tremendous upside so we’re really excited by what we see so far. This year primarily we’re focused on driving up production. A lot of that is going to be in the Southwest. Next year you’ll see us continue to drive production up there but also start to do a lot of drilling in the Northeast as well. David Tameron – Wachovia Capital Markets: Why type of lease commitments do you have in the Northeast for 2009? Jeffrey L. Ventura: We’re in good shape, we’re not really drilling right now the whole acreage although we’re cognoscente of that. We’re 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’ve added to it. Fortunately, we’re in stack pay areas, some of those leases are already held by production from shallower horizons that were produced there historically or deeper horizons in some cases that are produced historically and we’ve got good term on our leases. So, we’re 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. David Tameron – Wachovia Capital Markets: One more question on the Appalachian and then I’ll let somebody else jump on. Can you just talk about severance tax that’s floating around in the budget that was recently submitted I guess it was a couple of weeks back? Roger S. Manny: Just to give everyone a background, one of the unique things about Pennsylvania is it does not have a oil and gas severance tax currently. It doesn’t have a state income tax. There’s plenty of other taxes in Pennsylvania, don’t get me wrong but it currently does not have an oil and gas severance tax. With the short fall in revenues in the state the governor as well as some of the other legislatures have discussed publically the idea of instituting a severance tax. 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 swing them one way or the other but 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. It’s one of those things that’s interesting, the more you tax it early on the longer it’s going to take to ramp up and likewise. So, I think everybody understands, at least to a reasonable degree the issues, the question is what are they going to do and that we don’t know. We’re not naïve, 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’re certainly receiving the benefit now of having no severance tax but that’s kind of the way we see it. We’ll continue to monitor it to the extent that we can be helpful and provide education, we’ll continue to do that. David Tameron – Wachovia Capital Markets: What’s the timing on the budget just so we have that? Do you have that? Roger S. Manny: It’s not so much exactly timed to the budget but I would expect that they’ll discuss this and possible vote on something this year, no doubt.

Your next question comes from Joe Allman – J. P. Morgan. Joe Allman – J. P. Morgan: I guess Jeff, current production out of the Marcellus what are you guys running out there right now? Jeffrey L. Ventura: Of course we’ve got the plant at 30 million per day capacity, we’re 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 you’ve got to work the bugs out but we expect we’ll get production up pretty quick on that and I feel comfortable we’ll exit the year at $80 to $100 million per day net which again, I think is phenomenal or excellent particularly considering the number of rigs we’re running. We’re not running 20 rigs to get that rate. John went through the schedule of how we’re going to ramp up. We currently have three rigs and come the end of the year we’ll have roughly six rigs. John H. Pinkerton: In a way, it’s going to be a little bit like an offshore platform. We’re going to go from say plus or minus 30 million a day where we are today to 60 million a day once we get the first cryogenic plant on in April. So then we’ll max that out pretty quickly. We’ve got about 14 wells that we’ve already drilled that in some cases tested and in some cases not, they’re just waiting on the next phase of infrastructure so we’ll fill that up pretty quickly. Like in anything that’s mechanical, it will take a few weeks, maybe a month to sort all the kinks out and then we’ll fill that up. The good news is that our friends at Mark West are doing a terrific job. While they’re building the first cryogenic plant they’re 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’re real pleased with that. I couldn’t be happier. I give them an A plus. Frank and the guys at Mark West are doing a tremendous job. So, in our view we picked the right partner. They’re spending that capital we’re not and we’re really focusing on ramping up the production, driving down our costs and really trying to focus on the highest rate of return projects for us. So, from all that perspective it’s going great. 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 to 100 million a day, that looks good. That’s a tripling of our production, that’s an easy task but we feel very good about that. Then by the end of this year then we’ll have the wind to our back in terms of the infrastructure then we’ll be able to really ramp it up from there. Joe Allman – J. P. Morgan: But down in the Northeast though you do have to build some more infrastructure there right? To develop that? John H. Pinkerton: Yes but, it’s relatively easy stuff. What it is, is just pure midstream pipeline and gathering. It’s not big 42 inch lines. 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 in that if you think of the Appalachian basin and where the bulk, or what we think the bulk of the goodies of the Marcellus is going to be, I think it’s either four of the top six or five of the top seven largest pipelines in the US run right through the middle of the play. So, it’s not a question of having to build huge 36 and 42 inch lines to cart this and what not, it’s all about building anywhere from eight to 10 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’re working with Mark West on some of those things, we’re doing some of it ourselves, pipe is going in the ground. All that is going according to oil so we’re very pleased on that. Jeffrey L. Ventura: I was just going to add, remember as you get in to 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. Joe Allman – J. P. Morgan: How about these two vertical wells you drilled, is there a rule of thumb in the Marcellus and what kind of rates might you see on the horizontals based on the vertical rates you’re seeing? Jeffrey L. Ventura: It’s probably too early to say what the rule of thumb is. Obviously, a 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 outliers, I think it’s too early to come up with a rule of thumb but I would say with 6 million a day vertical well I would expect that we will be drilling some pretty exciting horizontal wells up there as well. Joe Allman – J. P. Morgan: 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? Jeffrey L. Ventura: Well literally back in September and October when we first came out with that oil and gas prices were significantly higher so you were probably looking at cash flow back then of literally $900 million to maybe close to a 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. Like John said, if prices recover next year we’ll have the wind in our sales and we’ll be off to the races. Joe Allman – J. P. Morgan: Roger, you talked about NOLs, I missed that number and that was a yearend number I think? Roger S. Manny: Joe, it’s $159 million is our yearend NOL carry forward. Joe Allman – J. P. Morgan: The acreage position you’ve got in the Marcellus the 900,000 acres, previously you use to talk about high graded acreage. How much of that do you think is high graded? Or, how would you characterize that? Jeffrey L. Ventura: Well, we’ve got about 1.4 million acres in the state so that roughly 900,000 was our high graded number. Joe Allman – J. P. Morgan: Lastly, John you talked about unique opportunities that you might pursue, what are you thinking about in particular there? John H. Pinkerton: I can’t tell you. But, I’ll 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 is really precious today is obviously capital to do things with, with the fact that the capital markets have gotten either shut down or they’re extremely expensive. So, really the thing that is just so critical this year is what you do with every dollar is really of incredible importance. 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 and we’ll continue to do that. With that being said, I do think that 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 the 24 million a day and all the ones that are 10 million a day hold in there at numbers that are going to exceed the 3 or 4 BCF that Jeff talked about. If you think about that, the question is then if you’re going to hit the 100 million a day, you’re 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’s something incredibly cheap where somebody is in trouble, do you take advantage of that? My view of it is and it obviously changes from day-to-day and it’s more arts than science is that ’09 what you want to do in my view is we want to hit double digit production growth at sub $2 drilling cost. Then, what we want to do is really be opportunistic and capture opportunities that are unique that will probably go away once gas prices go back up because, they will go back up. We all know that and try and capture some of those unique opportunities. The fact that a lot of these smaller companies, I mean we’re a small company but there are a lot of companies smaller than us that are really going to be in tough shape this year in terms of capital and borrowing bases and everything else. We’ve had a number of them come to us with different ideas and we’re going to be very careful about that just like we were last year. But, I do think this is a year where you will be able to do some things that will be very unique compared to the market two, three or four years from now. That’s all I’m saying. Just be opportunistic and take advantage of that. We make this business so much harder than it sometimes really is. If you really think about it the biggest determinant in terms of acquisitions, in terms of rate of return is the commodity price environment you’re in when you buy the asset. So, if you buy assets when prices are low the ability to make a good return on that is a lot higher than the probability when you buy assets that are in $100 price environment of oil and $10 for gas. 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 say core areas these are things that are literally right next door to or directly associated with some of the major things we’re doing. We will not be active at all in new plays outside of our core areas. Our sandboxes are plenty big enough right now to grow this company as we said anywhere from eight to 10 times with just the assets we own. While we’re going to be opportunistic we’re also going to be very focused like we’ve been in the past.

Your next question comes from David Heikkinen – Tudor Pickering & Co. David Heikkinen – Tudor Pickering & Co.: A lot of good questions so far, one thing that stood out was the Hill County well rates and what you’re seeing there. When you think about the 61 wells in the Barnett how many are down around Hill County now? Jeffrey L. Ventura: There’s going to be very few. Those wells that we’re going to be drilling like I said it’s going to be Tarrant and Johnson and the really core properties that are proven. I am excited that the team drilled 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’re going to focus on our highest rates of return best growth projects. David Heikkinen – Tudor Pickering & Co.: As you think about the splits of capital kind of a couple hundred million in the Marcellus and kind of $150 to $180 million in the Barnett, is that about the right order of magnitude or do you have the exact numbers for drilling capital? Roger S. Manny: You’re going to spend about $150 million in drilling in the Barnett, about $200 million or more in the Marcellus, about $75 million at Nora. So you’re big three is going to be 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. Jeffrey L. Ventura: A lot of that infrastructure and land is all going to be predominately in the Appalachian basin. David Heikkinen – Tudor Pickering & Co.: Then kind of final question, what are you thinking about 2010 hedges? John H. Pinkerton: A very interesting question. My view of it is the cure for low prices is low prices. So, David you were kind enough to ask the question so let me kind of expand it and I’ll get back and I’ll answer your question but let me speak just a little bit about what our view 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 if you think about ’04, ’05, ’06, ’07 everybody came out with capital budgets and production increases at the beginning of the year. What happened was all throughout the year people were increasing their budgets, doing acquisitions and increasing their production and reserve estimates throughout the year. That became very much the norm. I mean, we were a classic example, that little chicken John Pinkerton would come out with low double digit production growths and we’d end up every year at 20% as drilling did better and we did a few little acquisitions. I think 2009 is going to be the difference and I think what people are doing is reflective of that in that they’re coming out – I mean, 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. Then, we’ve got it I think three times since then and we may cut it again. We’ll continue to think about it. But, if you look at all the companies across the spectrum and there were like three yesterday and one today, everybody is cutting their budgets and they’re going to be decreasing their production targets throughout the year and we’re only in to February. We’ve only got 15% of the year done, we’ve got 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’ll come down a little further before they jump back up, you’re going to see people really cut back in terms of production growth. The other thing is that the rig market is in a free fall. 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. I think what it is, is a lot companies are looking around the portfolio and essentially nothing is economic at today’s prices. I think that being said I think the industry is showing a lot of financial restraint and they’re dropping rigs, people are paying money to get out of rig contracts, I’ve never seen that before. When you look at it you’re going to see a dramatic response on the supply side. The big question and David if you and I knew what the exact timing of that we’d be the richest guys on the planet earth is 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 the cure for low prices is low prices. Because of that we’re going to be very disciplined in the way we view the market. We are completely unhedged for 2010. We are going to be very cautious in terms of pushing those hedges on until we see numbers 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. Again, you’re going to see that and when it happens I don’t know when but it will happen. There’s no doubt in my mind. 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 E&P side, it’s clear that it’s going to happen. So, that being said, we’re going to hedge, we’re just not going to hedge at these prices.

Your next question comes from Michael A. Hall – Stifel Nicolaus. Michael A. Hall – Stifel Nicolaus: Kind of hammering on Northeast Pennsylvania a little more, can you provide any color in terms of what you saw in terms of reservoir characteristics or frac barriers, things along those lines with your vertical wells? Kind of in the context of Southwest too on a relative basis. John H. Pinkerton: I appreciate the question and what not. As you know, this play there’s still a lot of acreage out there to be leased and we’ve drilled more wells in the play than everybody else combined. We really view that as a competitive advantage. We’re still picking up leases so we’re going to be very quite in terms of the questions you just asked. So, I’ll have to just not answer it quite frankly. Jeffrey L. Ventura: I can give you the generic answer. We saw things we really liked and we ended up with a good well. Michael A. Hall – Stifel Nicolaus: Looking at the rigs you’re bringing up in to Pennsylvania, have you been able to renegotiate on any of those terms? And, what are the date rates you’re carrying on those rigs? Jeffrey L. Ventura: I don’t know that I’m going to give you specific numbers. What I will say is when you look around it’s been a very interesting year in terms of service costs. Like John said, people are dropping rigs rapidly and then you’re going to get in to differences in areas 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. In 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 have 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 to a 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’ve dropped. But, that’s a less competitive area. Obviously the midcontinent and Rockies are probably less competitive so I don’t want to get in specifically to what we’re 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’re really going to help us drive down our costs. That will get us in a true development mode once this first rig spuds and we start drilling and I expect we’re 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 the sort of offset to that somewhat is service costs are really coming down for everything from drilling rigs, to fracing, to steel and everything else. John H. Pinkerton: The interesting thing just to pile on to what Jeff said – the one thing that is 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. You look at it today and it’s less than half the rigs are working in the Barnett than there were six months ago. That is incredible especially given the Barnett shale is the largest gas field in the US 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 all this affects the Marcellus is that the equipment in the Barnett can be easily put on railcars or moved to Appalachia. So, I think we’re going to benefit from pressure pumping, the rigs and especially people. One of the largest drilling contractors in the US I saw him at a conference not too long ago and he mentioned now he’s got people lining up at his door willing to move to Appalachia. That wasn’t the case a year ago. So, the good thing is I think we’ll see some flop back there in terms of this whole service cost mumbo jumbo as it moves in favor of the Appalachia. As Jeff said, when you’re only paying an eighth royalty, when you’re getting premium to NYMEX versus $1 to $2 difference to NYMEX it sure makes those wells up in Appalachia a lot more economic on a relative basis. So, you’re going to see a lot of equipment I think move up to the Appalachia basin and that is just unbelievably good news for the Marcellus, not only for Range, but the entire Marcellus shale play in general. So, in some respects the pull back in prices is going to have a really profound effect in terms of the service infrastructure in the Marcellus. I think it’s going to be one of the direct beneficiaries. Michael A. Hall – Stifel Nicolaus: Finally, the asset sales, are any asset sales or production sales assumed in the current guidance of 10% growth? Or, how should we think about that? John H. Pinkerton: 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. But, if we do any material sells we’ll come back to you with the 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 later in the year and all the other stuff that comes in those kinds of things. Michael A. Hall – Stifel Nicolaus: What’s Fuhrman producing these days? Jeffrey L. Ventura: It’s about 16 million per day equivalent.

Your next question comes from Biju Perincheril – Jefferies & Co. Biju Perincheril – Jefferies & Co.: Going back to the Northeast, hopefully you can answer this, the well that was 6 million cubic feet a day, was that a simple vertical well in the single stage completion or did you try some of the multistage completion that competitors are trying out there? Jeffrey L. Ventura: Well, I will answer part of your question, yes it was vertical well but exactly how we completed it and what we pumped 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. 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’ll keep that tight. The other thing I hope you guys do appreciate is since we started this endeavor we’ve kept peeling back more and more layers of the onion, giving more and more information. So, we’re trying to be more and more transparent but because of competitive leasing reasons we’re going to have to keep some stuff tight. Biju Perincheril – Jefferies & Co.: Then in Southwest, I think you mentioned you hope to get to $3 to $4 million per well completed cost. What is actual cost running now? Jeffrey L. Ventura: Obviously they’re a little more than that but there’s three easy ways we’ll get there, maybe four. One, is we still have science in the wells and although trouble costs are coming down they’re not zero. If you eliminate the science and trouble out of our more recent wells we’d be $3.2 to $3.3 million. Obviously, once you know you drill 100 or whatever the magic number is 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. They may even break through the low end in the Southwest. Biju Perincheril – Jefferies & Co.: What’s the sort of spud to completion time in the Southwest now? Jeffrey L. Ventura: Spud to spud on our best wells is about 20 days, 21 days, something like that. Then they’ll 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 so depending on how long the lateral is and how many stages you have fracing may take three to five days or something like that. Biju Perincheril – Jefferies & Co.: With the fit for purpose rigs, what do you think that number can go down to? Jeffrey L. Ventura: Again, to use an analogy of the Barnett, we’ve gotten as low as 10 days per well spud to TD type thing. Depending on where you are again it’s a little more complex up there, you have cold strings and other things that you have to do. But, I think in time, maybe on well 200 or something out of 6,000 or however many we end up drilling, you might approach 10 or 12 days per well. I know our guys listen to these calls so there’s your challenge. John H. Pinkerton: Just to pile on what Jeff said, what’s interesting is what got us there – for example in Hood County, right on the corner of Hood and Johnson County where we’ve had a fair amount of success at the Mitchell Range, 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 and 18 and we drilled them on a single pad sequentially and we drilled all three of those wells in 31 days and I think cost were $1.6 to $1.8 million each completed. I think that recipe really holds true to any shale play quite frankly unless you’re in maybe the deeper part of the Haynesville that’s way over pressured and its 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 both in terms of vertical depth and laterals that we’re doing in Hood County Texas. From that perspective having fit for purpose rigs that are smaller that can move around instead of being 18 wheeler roads to move them like these big rigs we’ve got now that come down to maybe three 18 wheelers with no cranes, that’s a big cost savings in terms of moving it from location to location. The other thing is one of the things 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 Appalachia because the acreage blocks, I think our average lease is 200 acres so to the extent that we’ve had 30 years in some cases the aggregate all these acres and we’ve got big [yellow] blocks of acres to the extent that you can drill multiple wells from a single pad really reduces your road costs, really reduces your pipeline costs, it really reduces your mope cost on your drilling rig. That will save you an enormous amount of money. It all gets back to the efficiencies and what not and how you charter all this stuff out. Again, those are some of the things that we’re going to be really focused on during 2009. That’s how we’re going to get the cost down. If you think about some of the numbers that Jeff talked about, if it’s $500,000 per well that we can save in 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 of hundred, that’s $100 million. If we drill 100 wells next year that’s $50 million. It’s huge amounts of money. That’s why we’re so focused in terms of getting the per well cost down. If you think about the size of the play four years from now we’re going to have a gazillion rigs up there running so to the extent that we can save $300 to $500 per location with a gazillion rigs and you run that math, that’s a gazillion dollars. Jeffrey L. Ventura: Just to add on to what John saying not only is it cheaper, these new rigs are actually going to have walkers and stompers where you can 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 drill off a pad, you’re disturbing less land, it’s better for the land owner, you’re disturbing less of the land owners’ land. So, there’s a lot of other reasons to do that as well. It’s economically the right thing to do but for the land owner and the environment it’s the right thing to do too.

Your final question comes from Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.: On the decline rates let’s just say for your 24 million a day well, I know it’s very early but is it kind of tracking what you would see at a less of an IP rate well? Jeffrey L. Ventura: Let me put it this way, I’ll just be fairly straight forward, it’s early but a well like that could have reserves of 8 to 10 Bs or something like that. So, when we talk about average reserves of 3 to 4 Bs, like John mentioned when you’re getting these wells that are 10 million or 10 million a day plus obviously they’re 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 for a pretty reasonable amount of time approaching it will be two years this August and you plot those wells versus the Barnett and they compare very favorably. So we’re pleased with what we see so far. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.: When do you reach a statistical 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? Jeffrey L. Ventura: Well, it’s a combination of a number of wells and time. You need to 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’re in the high quality core best parts of the play or whether you’re way out on the fringe. So, you’re not going to be able to apply one number across the entire play. There’s going to be good areas in there and poor areas. Obviously we’ve 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 to $4 million per day for 3 to 4 BCF I certainly still feel comfortable with those numbers. When you consider that those kind of numbers at the midpoint of the play give you finding costs of just a little over $1 and rates of return that are pretty phenomenal regardless of what gas price you use, I feel really good about that. The other thing we’re learning in the play so far, it’s not just Ranges wells but you’re getting other peoples’ well that sort of confirm and validate the play as well. Going back to the Southwest, Range has had great results but that area, that 550,000 acres in a lot of way has been somewhat derisked 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 are others as well. Southwest will be drilling, there’s a lot of name brand companies up there and throughout the play. Rodney is queuing me in on some of the areas that haven’t worked so well and some of the other companies but I only like to talk positively about Range and our brethren but then you guys know what wells haven’t worked up there and I think where they are. We’ve put [inaudible] like that and talked about it in some of the conferences. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.: What about the kind of BTU content as you’re kind of moving in and around different areas, is that holding that pretty high rate that you’re initially seeing or are there some changes there? Jeffrey L. Ventura: Well, the BTU is similar to the Barnett you’re 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 areas, 1,300 or 1,400 BTUs. Then, if you just continually go west way in to Ohio some where you probably get oily just like in the Barnett if you go way, way west eventually you get oily. So, you’ll see that range throughout the play. There are good wells in the dry areas and there’s good wells in the high BTU areas. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.: Your average that we kind of heard this morning 6.9 that is a kind of BTU adjusted number, right? Jeffrey L. Ventura: No, that’s adjusted for liquids. That’s a million cubic feet per day equivalent, that’s not BTU adjusted. Obviously, once you process the gas, you produce the gas – I’ll just talk about the wet gas, you produce the gas, 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 1,150 to 1,200 and then we get paid that BTU uplift. So, in the wet areas you’ll get the gas plus a BTU uplift plus the liquids. So, really it helps the economics and enhances it and in the dry gas area it’s basically dry gas is 1,000 BTU, you get paid what you get paid. But, there’s good wells in both areas. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.: The last question, on the processing capacity front, you’re adding something early ‘010 as well, right? Jeffrey L. Ventura: We’re adding a big cryo plant that will either be end of this year or early ’010 that will really significantly increase capacity. The guys are doing a very good job of staying ahead of the drilling machine. We want to make sure we’re drilling the highest rates of return, best quality wells at the same delineating our acreage but, the pipelines and processing and takeaway are staying ahead of the drilling machine. So, we’ve got a good team working in a very integrated way to make sure we have all those pieces in place to continue to drive our success. John H. Pinkerton: The one thing that has been surprising is when we first put the infrastructure plan we used that kind of 3 to 4 BCF and we used the kind of IPs associated with that. So, what happened was when we hit some of these bigger wells in terms of just compression and what not we had a really high graded problem there. So, in some of these cases we tested wells and we just shut them in and we’re waiting for the infrastructure to catch up a little bit. But again, one of the really neat things about the Marcellus and there’s been a lot written on it is it’s really just a midstream issue and as the play really develops out there is no place on the planet earth you’d rather have gas than the Marcellus shale play because it really works in a big way. Some of the basis differentials you see in the Rockies is really going to affect other areas because this play is going to have such a monumental impact not so much us but 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 350 mile radius of Pittsburg Pennsylvania, home of the Super Bowl Champions Pittsburg Steelers. So, it’s a great place to sell gas. What’s interesting is it’s really neat to see some of the proposals we’ve seen 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 what not, it’s really cool. All that being said, we’re keeping our head down, we’re in the bunker, we just want to hit 100 million a day this year and we want to drive down our cost and drive up production. As Jeff has said, I think this is hopefully coming through loud and clear, we really feel like we’ve derisked 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 and as we get to the middle of the year we’ll be up more and a we get to the end of the year 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 getting more rigs and more people and making the commitment and driving it up. We’re doing that. We’ve got 108 people, knowing Ray he’s probably got 120 people as of today because he hires people faster than I can approve them. We’ve got more office space, we’re making all the commitments that we need to really drive this play up to be a really big time gas play. 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 [Curry]. We’ve just got a really first class – Dan [Cotterman] and [Greg Davis], we’ve got a real first class group of people up there that really know what they’re doing. They’re going to be driving the production up and if they can do it they’ll all get rich just like we will because we’re all fully invested in the Range. Rehan Rashid – Friedman, Billings, Ramsey & Co., Inc.: Just one more question, on the cost front Jeff I’m trying to remember my numbers but I think you mentioned that $3 to $4 million and then when we go in to development mode sub $3. As you kind of go out based on kind of service infrastructure 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 is a good number to settle it down to $2 to $2.5? Or, is that too aggressive? Jeffrey L. Ventura: I think once we get 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’ll be in that $3 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 drilling complete today and falling. You’ve got to remember, it’s not an apples-to-apples because you’ve got cold strings, you’ve got some different things in PA that you’ve 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’ve got a first class team up there and I think those guys will do wonderful things.

Ladies and gentlemen this is the end of our electronic Q&A session. I’d like to hand it back over to Mr. Pinkerton for closing remarks. John H. Pinkerton: We thank you all for joining us today. We’ve obviously run over and we appreciate you all that stayed with us. We had a lot of great questions. 2009 is going to be a real interesting year. We’re off to a great start. We’ve drilled some great wells. Our production looks on track and we’re going to behave ourselves in terms of the 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 in Range is really our portfolio, our projects, the Barnett is important, Nora is important but so is the production that helped support that and the men and women in those other divisions they do a terrific job as well. With that we’ll sign off. If anybody has any questions that we didn’t answer feel free to call any of us and we’ll be happy to answer those questions. Thanks again and we’ll 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.