Rodney Waller – SVP & Assistant Secretary John Pinkerton – Chairman & CEO Roger Manny – EVP & CFO Jeff Ventura – President & COO

Marshall Carver – Capital One Southcoast Leo Mariani – RBC Capital Markets Dave Kistler – Simmons & Company Ron Mills – Johnson Rice David Heikkinen – Tudor, Pickering & Holt Dan McSpirit – BMO Capital Markets

Greetings and welcome to the Range Resources first quarter 2010 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 speaker's 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 first quarter 2010 with record production, leading the consensus numbers and continued to execute our business plan with improvement in unit cost while navigation this period of challenging commodity prices. The first quarter marked our 29th consecutive quarter of sequential production growth. Although we are encouraged with our resource base to continue to grow production and reserves in the future, we are more focused on achieving those targets at an optimum cost structure on a per share basis to maximize shareholder value. I think you will hear those same things reiterated from each of the speakers today. On the call with me today are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; 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-Q with the SEC this morning. It's now available on the home page of our website, or you can access it using the SEC's EDGAR system. In addition, we posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDA and cash margins, and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you the detailed information of our current hedge position by quarter. Secondly, we will be participating in several conferences in May. Check our website for a complete listing for the next several months. Moving at (inaudible) it's going be held at May 13 to 14, on last 13 (inaudible) conference in Houston on May 21st, and the UBS Oil & Gas Conference on May 27 stockholders meeting will be held on May the 19th, with the help of each of the stockholder as received their proxy material and we urge each stockholder for the proposal being submitted in the proxy. Now let me turn it over the call to John.

Thanks, Rodney. Before Roger reviews the first quarter financial results, I will review some of the key accomplishments so far in 2010. First, on a year-over-year basis, first quarter production rose 12%, reaching the high end of guidance. This also marks the 29th consecutive quarter of sequential production growth. If you adjust for asset sales first quarter 2010 production would have been 18%. Second, our joint program is on schedule throughout the quarter as we drilled 72 wells. We continue to be very pleased with our drilling results and despite the lower prices. We are generating attractive returns on the capital. Currently, we have 22 rigs in operation. A 12% increase in production was more than offset by 16% decrease in realized prices. As a result, first quarter oil and gas revenues were down 6%, compared to the prior year. We are most pleased on the cost side as on our per unit production basis nearly all cost categories were lower than the prior period. In particular, direct operating cost came in $0.73 per Mcfe. This is 22% lower than the prior year period, quite an achievement. With regards to our Marcellus Shale play, significant headwind was made in the quarter as we continue to drill some fantastic wells filling our acreage position to test the other Shale formations and continue to build out infrastructure. In addition, we continue to add high quality technical personnel to our Marcellus team in Pittsburgh, which now includes over 200 people. Right at the end of the quarter, we completed the initial phase of our Ohio asset sale which generated roughly $300 million of proceeds. This sale included 3300 wells in over 13,000 leases. I'm really pleased that we were able to get it close so early in the year. All now I couldn't be more pleased on how much we accomplished in the first quarter. I think it's a real testimony to all of us here at Range especially the technical folks. With that I will turn the call over to Roger to view financial results.

Thank you, John. The first quarter of 2010 in some way was a lot like the first quarter of 2009. Production reached to record quarterly high 12% higher than the prior year and Range posted another solidly profitable first quarter despite oil and gas prices in the first quarter like last year been sharply low. Turning to a bit deeper into the numbers however, revealed a stronger operating performance in the last year, to significantly lower unit operating cost plus the balance sheet benefits having sold most of our Ohio tight gas sand properties at the end of March. Quarterly oil and gas sales including past settled derivatives totaled $233 million down 6% from the last year's revenue figure of 248. Once again unfortunately, the decline in prices just offset the benefit of higher production volumes. Cash flow for the first quarter of 2010 was $147 million, 7% below the first quarter of '09 with cash flow per share $0.92, $0.02 above the analyst consensus estimate of $0.90. EBITDAX for the quarter was $176 million, 5% lower than the first quarter of '09. First quarter of 2010 cash margins were down 18% from last year at $3.49 per Mcfe compared to $4.25 per Mcfe in 2009. There were a few extraordinary revenue and expense items going through the financial statements this quarter starting with the pretax unrealized marketing and market gain on our hedges of $46 million, and a $69 million pretax book gain primarily from the sale of our Ohio properties. On the expense side, we have $7.9 million in severance cost from Ohio sale along with the $6.5 million low gas price in dues impairment of the Gulf Coast property. Lastly, as our stock price declined slightly during the quarter, we reported non-cash income of $5.7 million related to our deferred compensation plan, and quarterly GAAP net income was $78 million. Quarterly earnings calculated using analyst methodology for the first quarter, which excludes non-recurring items such as asset sales, unrealized derivative mark-to-market entries, that was $26 million or $0.16 per fully diluted share and that's $0.02 higher than the analyst consensus estimate of $0.14. As Rodney mentioned the Range Resources website contains a full reconciliation of these non-GAAP measures I just mentioned including cash flow, EBITDAX, cash margins and analyst earnings. These non-recurring items should not math some of the recurring good news found deeper in the expense line to the income statement. And first up on the good news was as John mentioned is the cash direct operating expense reduction per Mcfe of $0.023 in the first quarter, compared to $0.93 last year. This represents a 22% decrease. Direct operating cost is now running 30% below, its peak of a $1.05 per Mcfe in mid-20008. The news gets even better when looking ahead into the second quarter this year when we expect to see the full benefit of selling the higher cost Ohio properties take hold. The sale should further reduce direct operating cost per Mcfe by another nickel. That would bring it down to the high $0.60 range. Production factors have drifted lower with the decline in property taxes and production increases in low tax jurisdictions resulting in production taxes down to $0.19 per Mcfe in the quarter, compared to $0.22 last year. G&A expense adjusted for non-cash stock comp was $0.49 per Mcfe for the first quarter of 2010, that's down $0.01 from the first quarter of last year. G&A expenses per Mcfe will likely stay flat around the $0.50 mark as G&A dollars were shifted from areas where we have sold assets to areas such as the Marcellus, where we continue to create jobs and add numerous professionals and technical support members to the team. Interest expense for the first quarter of 2010 was $0.72 per Mcfe that's $0.01 higher than the first quarter of last year, and that reflects the shift from short-term floating rate debt, long-term fixed rate debts that we made during the second quarter of last year. Interest expense should remain flat for the next few quarters with most all of our debt appearing fixed interest rate, and the cash on hand from the Ohio sales available for summer capital program. Exploration expense for the first quarter of 2010 excluding non-cash stock comp was $13.5 million. That's $1.2 million higher than the first quarter of last year due to primarily the higher delayed rentals. We anticipate that quarterly exploration expense excluding non-cash comp will approximate $15 million to $18 million in the second quarter due to seasonal size and making delayed rental increases before falling back to the $10 million to $12 million for quarter range for the rest of the year. Depletion, depreciation, and amortization for Mcfe for the first quarter were $2.12 and that's compared to $2.25 in the first quarter of last year. The figure consists of a $1.97 per Mcfe in depletion expense and $0.15 attributable to depreciation and amortization of all other assets. Our DD&A rate has declined considerably from the $2.34 Mcfe rate for all of '09. The lower depletion is primarily from the continued favorable performance from our Marcellus wells and well the DD&A rate will fluctuate quarterly going forward with our production mix. We anticipated DD&A rate in the 215 to 220 per Mcfe range for the rest of the year. Abandonment and impairment of unproved properties came in at $12.4 million in the first quarter plus down $7.2 million from the last year. Investors may expect to see in abandonment and impairment figure for unproved in the second quarter of approximately $12 million to $14 million. Range incurred $49 million in the deferred taxes for the quarter but paid no cash taxes. Following the following of our year-end federal income tax return, our NOL carry forward is now $322 million. Our effective rate for the rest of the year is anticipated, it could be 38.5% with all cash federal tax payments deferred. Cash state taxes were approximately a $1 million for the quarter. Now while we are on the subject to taxes, you may have noticed that we have elected to play the bulk of the Ohio asset sale proceeds in the like-kind exchange account, but the interest rate on our bank facility hovering around 2%. We felt that the negative carry incurred represent a small price to pay to the ability to possibly differ some or all of the estimated $255 million gain on Ohio transaction and the cash is completely unrestricted and we may move the funds out of the account any time we desire. The remainder of 2010, Range has approximately 77% of its gas production hedge with collars at a floor price of $5.53 per Mmbtu and a cap of $7.21 per Mmbtu. We now have approximately 51% of our anticipated 2011 gas production hedge with collars at a floor price of $5.73 per Mmbtu and a ceiling of $6.83 per Mmbtu. On the oil side, we have 1,000 barrels per day in 2010 hedge using collars at $75 by $93.75 and approximately 5200 barrels per day hedge in 2011 with the collar of $70 by $90. The size of the previously mentioned asset sale proceeds parked in cash on the balance sheet. There were several other balance sheet items worthy of mention. First, despite significant asset sales on March 30, the Range Bank Group reaffirmed the existing $1.5 billion borrowing base to an extermination date of October 2010. We elect to retain the existing $1.25 billion commitment under the borrowing base and no changes to the loan structure or interest rates; structure was required with the reaffirmation. And second, unlike last year when we were outspending cash flow during the first quarter anticipating asset sales would occur later in the year. This year we have completed our asset sales by the end of the first quarter effectively removing any financing to transaction service from our 2010 capital plan. The benefits of discipline spending and a completed asset sale may also be seen in our debt to cap ratio letting the cash balance against our bank debt produces a net debt to cap ratio at the end of the quarter at 36%. This places our leverage below our targeted 40% ratio, and it compares favorably to the 43% ratio at the end of '09s first quarter and the 47% ratio in 2008. Our leverage ratio below target gives us additional flexibility as we move through the year. In summary, the first quarter of 2010 was a stronger quarter operationally with continued double digit production growth accompanied by double digit unit operating cost decline. The first quarter was also a strong quarter strategically with the Ohio asset sale completed over a $1 billion in liquidity in our hedging programs delivering cash flow certainty during periods of low prices. Overall we are entering 2010 on a much firmer footing than 2009. Last year, when we started the year, we were sharing rigs and reducing activity to fit the 2009 budget while just commencing the sale of our affirming assets, while this year our significant asset sale is already done, and we have the flexibility of entering the second quarter having under spent our 2010 capital budget on a pro rata basis. John, I will turn it back to you.

Thanks, Roger. Terrific update; I'll now turn the call over to Jeff Ventura who will review our operating activity. Jeff?

Thanks, John. I will start the operations update with the Marcellus Shale. Our strategy at Range is and has been growth of low cost. Range's Marcellus production has the best economics of any large scale, repeatable gas play in the U.S. There are basically four reasons for these. The first is this discovery in the Appalachian Basin, which is in close proximity to the best gas markets in the U.S. Therefore, the gas produced here is advantaged versus other gas in the U.S. It doesn't have to be transported forward to get to the end users. Second, not all layers in the Marcellus or any other gas play for that matter are equal. To have the best economics, you will have to be in the core part of the play where the rock quality is the best. Range clearly has a great position in the core as evidenced by the high quality wells that we have drilled in combined with the way which we've been able to grow our net production with relatively few rigs. The third reason is that Range discovered the modern Marcellus Shale play and has a strategic first mover advantage. Since we were the first to pursue the play, our acreage acquisition cost is very low, which significantly impacts our economics in a positive way. The fourth reason, our economics is so good perhaps the best in the Marcellus play so that we are in the wet gas portion of the play, which relatively speaking is a small part of the total Marcellus acreage. It exists in the Western half of the Southwest portion of the play, primarily in Southwest Pennsylvania and into the West Virginia Panhandle. Given our gas prices and oil prices are if you are processing which Range does through our contract with MarkWest, this is a huge benefit. The NYMEX Henry Hub price is $5 and NYMEX WTI is $75 per barrel. The effective price per Mcfe that Range receives is $7.28 per Mcfe. For an equivalent well in the wet gas area versus the dry gas area, this more than doubled the rate of return. As good as these wells are, we constantly strive to make them better. As shown on the most recent IR material on our website, we have continued to evaluate longer laterals and more frac stages. We have shown every horizontal well that we've drilled in the form of zero time plot by program year. Importantly we've continued to improve the quality of our wells year after year, although other Shale plays had the same characteristics, we are unique in our play with economic very early on. Other plays require a lot of time, long laterals and a lot of frac stages to make them economic. The fact, that the Marcellus business is evidence of the high quality Shale that we have relative to the other Shale plays. Given the excellent performance of our wells in the core areas coupled with improving completions, we have increased the range of recovery estimates for our wells from 3.4 Bcfe up to 4 Bcfe to 5 Bcfe. We've also adjusted the expected cost of our development wells in the Southwest Pennsylvania from $3.5 million to $4 million per well. This increase is a direct result of going to longer laterals in more frac stages. The bottom line is a better rate of return, lower finding cost and better efficiency. The build out of the infrastructure continues on plan. Oil capacity will be increased to MarkWest from 155 million per day to day to 290 million per day by mid-2011. Dry gas gathering and compression capacity in the Southwest will be increased from 20 million per day to day to 65 million per day by late 2011. Dry gas gathering and compression capacity in the Northeast through our PVR contract will come online late this year and will be 120 million per day by late 2011. In aggregate by late 2011, we have the infrastructure capacity of 575 million cubic feet per day. As you can see we are on track to reach our Marcellus production target of exiting this year at a net rate of $180 million to $200 million per day in exiting 2011 at a net rate of 360 million to 400 million per day. We have a first class team of more than 200 people located in Southwest Pennsylvania focused on this project. Given our team, our acreage and the infrastructure that we have in place in the works were well positioned to meet or exceed our plans for the Marcellus. We've have also drilled, and tested one horizontal Upper Devonian well, and one horizontal Utica well in Pennsylvania. This is the first horizontal Utica well in the entire Appalachian Basin and the first Upper Devonian Shale well on Pennsylvania. Both wells successfully tested gas. However, we plan to keep the results confidential for a while due to competitive reasons. We plan to drill one or two more horizontal wells in each of our horizons by year-end. In regard to our 2010 budget, 77% of our capital going on to the Marcellus Shale that's because Marcellus is our highest rate of return project. In addition outside of the Marcellus, almost all of our acreage is held by production, where we own the minerals and hold it in perpetuity. Therefore, we have the flexibility to pull back spending in our non-Marcellus projects. We have decreased our 2010 budget for Nora by about 50% versus 2009. In the Barnett, we dropped from 68 rigs about 15 months ago to one rig to two rigs today. The projects in both areas have good rates to return at today's prices. It's importantly we will continue to monitor them and look at the rates to return on a real time basis and adjust accordingly. The final area I want to mention is our Mid Continent division. We are planning on spending about 7% or $70 million of our 2010 budget there. We are primarily targeting a new play that we discovered to St. Louis. We believe we can spend about $1.3 million per well to get about 2 Bcfe in reserves. Importantly, it also has an oil component which on top of the strong F&D helps with the economics. From the early stages of the play, we are also drilling some Granite Wash wells and a couple of horizontal Mississippi and oil wells in existing fields that we have in the sectors Panhandle and Oklahoma. At Range, our strategy is to grow production with one of the best oil and cost structures in the business and to build in high grade our inventory. In addition to adding high quality place like the Marcellus Nora and the Barnett to our portfolio will sold out of the Gulf of Mexico, Ohio, New York, Fuhrman Mascho and other fields and net result is shown on our website in our latest IR presentation. In 2007, although we have decreased our well count from about 14,000 wells to 6,000 wells, production from 2007 to our 2010 forecast is projected to increase from 320 million per day to about 490 million per day. Quite simply in 2007, we decreased our well counts by 57% while increasing our projected production by 52%. Bottom line we are a much more efficient company. The combination of adding higher quality plays and focusing our people and capital there, well selling relatively high cost, low growth periods have led to better production in reserve replacement, lower F&D, lower LOE and better rates of return. This in addition to our resource potential which is ten times our current reserve base coupled with one of the best teams in the business will lead to you an exciting future for Range. Back to you, John.

Thanks, Jeff. That was a terrific update. Looking to the remainder of 2009, we see continued strong operating results here at Range. For the second quarter, we are looking for production to average, second quarter production for 2010 to average 450 to 455 million a day representing a 10% increase year-over-year. The second quarter production reflected sales, the Fuhrman Mascho properties last June, the New York properties last December and the Ohio properties in March of this year. So, the 10% second quarter growth target equates to 18% after adjusting for the property sales. However, given that we sold the Ohio properties right at the end of the March it is unlikely we will be able to make up the full amount of the Ohio production loss of 25 million a day in the second quarter. As a result it is likely our straight 29 consecutive quarters of sequential production growth will come to a halt. As I've said in the past, I would not be disappointed to see this to retain if that was in our best interest. Clearly the Ohio property sale wasn't our best interest given the terrific price we received. For the year, we still anticipate with our production growth target of 13% even after accounting for the property sale. Now that we close the Ohio property sale, I will take a moment to look at the impact of our divestiture program. Over the past three years, we have reduced our well count by roughly 6000 wells. This represents 57% of our well count, but only approximately 9% of our production reserves. The properties we sold were more mature higher cost properties. The good news is that while we were selling our mature higher cost properties, we were focusing on our capital into higher return projects like the Barnett Shale, the Nora area and the Marcellus Shale. As a result despite of the asset sales, our production reserves continued to increase. Over the same three year period that we saw, our well accounts decline 57%. Our production rose 52%. As a result Range is a much more efficient company. We would like to say we are doing more or less. By less, we mean less well lower find development cost, lower operating cost etcetera. The first quarter results partially reflects the slower cost structure, which should continue in the subsequent quarters especially in the second, third quarters after the Ohio sale. The Ohio property is no longer running through our income statement. Over the meantime, this will have a significant positive impact or NAV per share. This is critical to generally attractive returns in a low gas price environment. In addition by having fewer wells and properties and more compact asset base, we can better focus our technical team on higher return projects and hopefully make those projects even better. Lastly, one of Range's hallmarks is to keep things simple. By having zero wells and properties, Range is by far a simpler company allowing the Range team to focus more on driving up our per share value. I believe the timing of the Ohio sale as important even the outlook for natural gas prices and the amount of gas in storage as we entered the 2009 winter heating season. We made the decision to accelerate the timing of the Ohio sale into the first quarter 2010 versus later in the year. Conversely we did the opposite with regards to our 2010 capital program and that we intentionally designed the program where less capital would be spend in the first and second quarters and more capital in the third and fourth quarters. As a result in the fourth quarter, we spend only 30% of the 2010 capital budget versus 32% in the first quarter of 2009. The combination of getting Ohio sale closed in the first quarter and slower spending puts us in a terrific position for the remainder of the year. As Jeff mentioned, one of the key elements that is having a positive impact on our results this year related to our capital efficiency. In the past several years, we spent considerable capital in the Marcellus play without seen much of return. The gain in 2009 this all changes the first phase of the infrastructure was completed and production began to ramp up. As our Marcellus production continues to ramp up in 2010, we are seeing the capital efficiency having an ever increasing impact. For the remainder of 2010 and for 2011, this will be the more evident as we get the capital efficiency impact to the Marcellus ramping up as well as the full benefit of the asset sale. Because of our drilling success so far this year completing the Ohio sale, our lower cost structure and our hedges in place, we are confident that we will achieve our 2010 production growth target as well as rating our Marcellus exit rate of 180 million to 200 million a day by year-end because of the terrific infrastructure progress we are making both the Southwest and Northeast portions of the play, our goal of reaching an exit rate of 360 million to 400 million a day net in 2010 and 2011 looks very, very good. What gives me added confidence is the quality and the size of our team in Pittsburgh. As Jeff mentioned, we now have over 200 employees in Pittsburgh working on the Marcellus full time. This is roughly double the number of employees compared to this time last year. One item, Roger touched on is our current hedging position. As you probably noted we have increased our 2011 natural gas hedges is 51% of our anticipated production at a floor price of $5.73 and a comp of 683. Our fair tails [ph] are fairly simple and that we wanted the blocking cash flows that we could fund our capital fund program for 2010 and for 2011. By many of you I'm concerned about the number of rigs drilling for natural gas in the U.S. I'm also concerned with the ready access to capital that the industry enjoy. While I'm convinced the industry will ultimately adjust capital spending to fit gas prices, we are taken the timing of the industry response of the table by locking in floor on half of our gas production for 2011. Speaking to the industry's ready access to capital, there have been several large joint ventures in the Marcellus off late. Clearly the Anadarko Missouri transaction and the Atlas Reliance transaction are starting to see as one to where to apply those valuation to Range's Marcellus acreage position, one can justify the Range stock price more than double what it trades today. This is great news and that others are beginning to understand and pay for the superior economics that the Marcellus Shale play has achieved. We think overtime as more wells are drilled and more to play at the risk that in acreage joint venture prices will increase. I remember mainly people saying Chesapeake deal with (inaudible) 5800 per acre was terrific in that range to consider the same. Just 15 months later, we've seen material reliance payable 14,000 per acre roughly 2.5 times what (inaudible) will pay. While Chesapeake, and Anadarko, and Atlas had balance in company's specific reasons to enter into their joint ventures, we believe joint ventures are what they really are which is a sale of asset. As we've said before, we preferred to sell our lower quality raw material asset not our higher quality higher growth asset. Most importantly, we believe that as the Marcellus continue to be de-risk by more drilling that the acreage prices is in the better part of the play will continue to increase. We believe our job is to maximize the value of Range's assets for the benefit of our shareholders. That been said, we will consider joint ventures for possibly selling a portion of our Marcellus acreage. However, we want to receive fair value, which we believe will be higher as the play continues to building risk. Additionally, we believe we have the highest quality acreage position in play. The best infrastructure arrangement and the best technical team, therefore we believe if we monetize any portion of our position we should receive a premium price. In summary, looking at Range today, we have the largest drilling inventory in our history. We now believe we have roughly 30 Tcf of resource potential, which equates to nearly 10 times of our existing crude reserves. We have obviously a cost structure after the asset sale that's going to be very low. So, while we are excited about the growth potential range, we are intently focused on delivering this quarter. Our first quarter of 2010 is a shine example of this commitment by all the employees of Range. With that operator, let's open the call up for questions.

Thank you, Mr. Pinkerton. The question-and-answer session will be conducted electronically. (Operator Instructions) Our first question is coming from the line of Mr. Marshall Carver with Capital One Southcoast. Your line is now open. You may proceed with your question. Marshall Carver – Capital One Southcoast: All right, just a couple of questions. The St. Louis and Stron [ph] areas where you drilled some successful wells, how many locations or net locations do you have in each of those areas?

Well, St. Louis is very early for us, but we've got a good acreage position that we are building. We got close to 40,000 growth acres and we think approaching 250 potential growth locations, so it can be very impactful. We are going slow. It's early on, but so far we are encouraged by what we see and it's particularly it's just great economics, $1.3 million for a little over 2 Bcfe coupled with the fact that you got an oil component, wells have come online and 2 billion with 50 barrels to 100 barrels of oil per day. The gas is relatively rich even after that 1080 BCU. So, we are excited by the play before our guidance generated up there. It's early on and then in the strong not as much potential so that when you look at the acreage you're having and things we could acquire and again it's early on in the play that we drilled several great wells. IP is of 300 barrels to 700 barrels per day rift out with in aggregate. It could approach 100 wells overtime if we continue to successfully grow and acquire a few things that we see. So, the guys are doing a good job not only in driving up production in the Marcellus and in making better and better wells, better economics, keeping all eyes on the ball there, but the guys in the other division are extracting a lot of value out of our old properties in old areas. Marshall Carver – Capital One Southcoast: Okay. That's very helpful. Thank you.

Sure.

Thank you. Our next question is coming from the line of Mr. Leo Mariani with RBC Capital Markets. Your line is now open. You may proceed with your question. Leo Mariani – RBC Capital Markets: John, I guess you just mentioned you potentially would consider a JV in the Marcellus or some acreage sales for the right price. Seems like a bit of a shift from what you have been saying in the past. Can you talk a little about strategy behind this? Is this more of a value unlocker for Range because it appears as though you have plenty of capital to execute your near terms plans here?

Yes Leo, it's a great question. And I appreciate you asking it. Maybe I wasn't – as I should have been, but historically our strategy is always been at Range. We are going to do what's in the shareholders best interest, and therefore, I didn't think, our team didn't think doing JV is a relatively low prices make any sense because like as you said, we really didn't need the capital to exploit it. As things move along in the play and clearly Chesap did their deal at 5800, Atlas and Anadarko did their deals at 14,000 or better. We think those prices are going to continue to move up. So, over some period of time we think that the price that repay will come closer to what we think fair value is and so we will continue to monitor that and if we think we are getting something that we believe is in fair value and its NAV accretive when you take the time value into account. We think that is in our shareholders best interest and we will – we've look at it very closely. We consider that and take it to the Board to get their input. So, again it all comes back to driving up on NAV per share. So, if we can do that don't screw up the balance sheet, will screw up the simplicity of the company materially will look at those for the best interest for the shareholders and we will move forward with that and as you can imagine with all the different things that add there, we had lots of discussions with lots of people. We will continue to have lots of discussions with lots of people and we will do the right thing. Leo Mariani – RBC Capital Markets: Okay. Just switching gears here, in your press release you talked about seeing some encouraging things in your initial horizontal well in the Utica and the Upper Devonian. Have you production tested these wells or flow tested them at this time here?

Yes, we have. When we talked about on the last quarter because we have drilled them and logged them and we are encouraged by what we saw based on ETS launch and such, and shows we have now drilled in case tested on, and in the press release, we mentioned that we are going to be looking a lot. So, clearly refine gas, but in general with any specifics we are going to hold that pipe very early on in the play. Importantly, I think I just want to reemphasize that we think the most perspective part for Upper Devonian Shale is primarily in the Southwestern portion of the State. Actually, they have the right thickness in large properties of making perspective and we are looking at all the various things that make Shale plays work. And in the Utica Shale, we think it's primarily perspective on the Western half of the State. The good news is we've got 1.3 million acres in the State from primarily all in Pennsylvania of which 600,000 acres are in the Southwest portion of the play. So, a lot of our acreages perspective for that is the big upside. We are encouraged by what we see early on, but it's early. We've drilled a couple of more wells probably by the end of the year and like we were with the Marcellus a few years back. We will keep it relatively applied and make sure we capture that. Therefore, our shareholders, it's good news as a lot of it is stacked on our existing acreage. So, we've captured a lot already, but Rodney said there would be things would want to fill in. Leo Mariani – RBC Capital Markets: Okay. One other thing; you guys mentioned in your press release as you're taking your EURs up on your Marcellus from 3 Bcf to 4 Bcf to 4 Bcf to 5 Bcf for your "high" graded acreage, is your high graded acreage – is that just the same thing as core 900,000 acres?

Yes and our acreage, gas is again 1.3 million acres basically within the fairway 900,000 that is high graded in it. It's really well positioned I've mentioned before there's been over 600 wells in the Southwest , Range wells and others both vertical and one horizontal, a huge portion of the acreage in the Southwest . The other 300,000 acres in the Northeast is predominantly a lay down where Anadarko and Mitsui did their deal. They haven't put it up specifically but a lot of its like homing, plus or minus accounting on either side like Bradford, Lycoming in there. So we feel, given the industries result to date that the very high quality acreage as evidenced by the quality of wells and evidenced by the deals that John mentioned. Leo Mariani – RBC Capital Markets: Okay. I guess the last question for you guys. Obviously your direct operating costs LOE looked great this quarter. It sounds like that's going to drop again next quarter. Can you give us any kind of ballpark as to where that can go this year?

Yes, I think Roger mentioned that it's going to drop another nickel or so. So it will be in the mid-to upper $0.60 next quarter. Leo Mariani – RBC Capital Markets: Okay. Thanks a lot guys.

Thank you.

Thank you. Our next question is coming from the line of Dave Kistler with Simmons & Company. Your line is now open. You may proceed with your question. Dave Kistler – Simmons & Company: Good morning Dave.

Good morning Dave. Dave Kistler – Simmons & Company: Or I guess afternoon. I apologize. Let's see. Just thinking about your drilling activity over the next few years and more specifically as you reiterated the $360 million to $400 million of production by year end 2011 out of the Marcellus. Can you delineate what portion of that is going to be coming out of the Northwest PA portion and what portion would be coming, obviously the balance of the Southwestern portion?

We can guide you somewhat. Through the end of this, we're not going to have the Lycoming County from Northeast until the end of this year. So basically and that's in almost all of the $180 million to $200 million per day net – and again, I want to emphasize the word net – will be coming from the Southeast and predominantly from the wet gas portion, almost all of that. When you project going into next year, a lot of our drilling is going to be in the Southwest although we'll start to ramp up the Northeast. So the vast majority of it in those early years is going to be coming from the Southwest and from the wet gas part of it. Beyond that we'll start to see a good contribution from the other areas. Dave Kistler – Simmons & Company: Okay. And diving into your hedges a little bit, when I looked at the 2011 hedges, if we just run oil production relatively flattish for you guys or liquids portions, whatnot, it ends up being over 90% hedged. So I'm gathering that there is – relative to any announcements you made about Stron [ph] and other areas, that we should be anticipating an uptick in the liquids production as well. Can you just give us some additional color there?

Yes, that's intuitive. If you just look at the delta change in the liquids, our liquids production is going to go streaming up this year and next year and next year for example we think the liquids production will be more than twice of what the oil production is and be heading north from there. So pretty intuitive question and again we really kind of circled back around with what Jeff was talking about in terms of the wet gas area of the Marcellus and in particular, when you're in a low price gas environment, a high price oil environment, the benefit of being in wet-gas is dramatic and so I mean, again as part of the message or the madness in terms of how we developed our acreage position and what we're doing and why we're doing what we're doing is well encompassing all that. Dave Kistler – Simmons & Company: Okay. So if I look at percentage hedges right now and I just try to project growth, I think the same quarter percentages are what you're going to be targeting for 2011 if I want to project the oil and liquids growth that I should be thinking about?

I'm not following you completely. I just – it's really hard to hedge liquids and most people who hedge liquids, they simply hedge oil. So we look at it as a basket. Clearly our biggest percentage of our production is going to be natural gas. So we're kind of focused on that, especially given where it is today. If you want to get into the details of the oil versus the NGL I suggest you call Rodney Waller and he can run you through all those detailed numbers after the call. Dave Kistler – Simmons & Company: That's great. That's actually very helpful, and primarily I was focusing more on the oil component piece just as you have shown those hedges for 2011. But one last thing on liquids if I can sneak it in. Everybody is obviously trying to take up their liquids components in this current environment. You guys have great position there. How are you thinking about that? Do we worry that liquids over time become pressured from pricing standpoint as everybody is seeing that same sort deviation in value and obviously wants to capitalize on it?

Again, that's a very intuitive question. It's something that our marketing team has really looked at very carefully. When you look at the Marcellus, the wet-gas area is a relatively small percentage of the total acreage in the Marcellus. So therefore the liquids component and the liquids that's going to be generated from the Marcellus, when you look at the entire play, it's not as big as I think some people have anticipated. That being said, one of the reasons why we chose to do our venture with Mark West is their expertise, when it comes to liquids and how you distribute the liquids up in the Northeast and we'll give you an example. Within 12 months we'll have a propane line in and we'll be selling our propane 12 to 24 through a pipeline. We're putting a rail for it and so instead of trucking the liquids we'll be rail-carrying the liquids out and the good news is, almost all of that will be used in the Northeast. There is some very good markets in the Northeast for all that stuff. So we analyzed that and don't see that there is any issue. In fact one of the good things that's happening is on a relative basis on liquids everything, we're seeing a higher price for liquids as they come out of Marcellus and we are in other places because the market is so robust in the Northeast versus the other parts there is more competition and more liquids coming onto the market. So that's kind of how we look at it on a 50,000 level.

And just to be crystal clear adding onto what John is saying, the wet-gas part of the Marcellus of the total play is small but Range sort of dominates that wet-gas part which is an advantage we have. A big part of what we have is a small part of the total play for the industry.

And one thing I can do is direct you to probably Mark West's website. Randy Nickerson made a presentation last week at Doug East Marcellus Midstream conference in Pittsburg showing what the total demand of Appalachian products were or each of the components built in the winter and the summer markets and showed what our production would be that is going to be largely, maybe a third of capacity is it possibly weak during the three to four years. So therefore I think the mid information about the market being overrun, to reiterate what John said is because the markets we are selling to in Appalachia have to get all the labels out of the Gulf Coast and pay a transportation charge for it, we can compete very competitively with those. We can avoid the large transportation charges coming out of the Gulf. So it kind of ensures a ready market for us and people, they really are able to take that as long as we can give them consistent quality and consistent quantities. Dave Kistler – Simmons & Company: That's very helpful, guys. I appreciate the additional color there.

Thank you. Our next question is coming from the line of Mr. Ron Mills with Johnson Rice. Your line is now open. You may proceed with your question. Ron Mills – Johnson Rice: Hi guys. Just a question on leasing and lease expirations. I know you have plus or minus 15% of your budgets going towards leasing. Can you add a little direction in terms of how much of that is new leasing and is most of that directed in continuing to fill out your Marcellus area and how much is dedicated to re-upping leases with current lessees?

Hi Ron. This is John. Pretty good game last night, huh? Ron Mills – Johnson Rice: Yes. I think the fix was in.

Great question, Ron. We, and let me just start at a high level. Then I'll work down. We haven't been by any what I'd call trend acreage in the play for two years. What we've really been doing, and the reason is because we grow a bunch of wells and we drill our first – completed our first well in '04 and we drilled a bunch of wells in '05 and '06 in areas that we thought were really, really, really perspective. So we immediately started buying acreage in there for a $50 to $100 an acre and it moves up to $500 an acres. So in most of acreage we've got relatively cheaply and most of them have very low royalty burden. So we're in terrific shape. What we're doing now, what we've done the last couple of years is we're simply filling in the holes in those big blocks of acreage we've got to try to continue to block our acreage position. We believe strongly and the Barnett is a perfect example, the Fayetteville is a good example and the Woodford is a very good example, if you can block up your acreage it really helps dramatically in rolling your costs as you go forward and it's everything from pipeline costs to road costs to infrastructure costs. All those costs go down and the economics of the play go up. So our budget this year is to do a number of things, one filling the hole. The only thing is we've got a huge average position, 1.3 million acres. We are not going to hold all that acreage from drilling. So we have to decide each year, what do we want to hold, what do we want to let go. The good news is everything that we've wanted to hold this year, we've already really, that we haven't drilled. So that's already done and some of what we want to do next year has already been done as well. So part of the budget is going to filling the hole. The other part is going to be really from some of the acreage that we're not going to get through currently. The other thing we're doing also is and I think the industry – it took a while for the industry to kind of catch up with us quite frankly but there is a lot of companies and a lot of good companies that have acreage that is spread out all over the play and as they drill wells, they start becoming, they start developing their little core areas. So we've talked to a lot of different companies about spreading acreage and we'll say 15,000 acres over one of our core areas for 15,000 acres they have in one of their core areas assuming they're relatively equal in terms of quality and royalty burdens and exploration. So we've done that. We're going to continue to do that. It is something that we think again will allow Range, in a big way in investing industries to block up the acreage and make it more valuable. Acreage that is blocked up is much more valuable than acreage that's not blocked up. And a perfect example of that is Matsui and Reliance paying $14,000 an acre for these big blocked up areas. You don't have to pay $14,000 an acre to drive at least 100 to 200 to 300 acres spread out all over the state of Pennsylvania. Those are still going for values much, much, much lower and quite frankly they should because the value creation is a combination of blocking up the acreage in good areas, having a really good technical team that can execute. So hopefully that answers your question. Ron Mills – Johnson Rice: It does. And then I think, Jeff, normally you walk through your production on an area by area basis. Was curious if you had to breakdown Marcellus versus Nora versus the Southwest division?

If you look at the major plays, we're looking at; we're on track to hit our $180 million to $200 million in the Marcellus. Today we're approximately $130 million per day net, something like that. The Barnett is working at $120 million to $125 million, Nora, about $65 million per day. Those will be top three and the rest of it is a lot of legacy price-gas standard of oil production. Ron Mills – Johnson Rice: And then in terms of the timing of production ramp, particularly in the Marcellus, obviously you'll have some come on at the end of the year in Northeast Pennsylvania. But in terms of March from $130 million a day to the $180 million to $200 million a day, how consistent is that over the remaining three quarters or are there major infrastructure bottlenecks being relieved at a particular date?

No, I mean infrastructure in the Southwest predominantly will be there. Because of the fact, some of that – we're doing a combination of pad drilling to drive up rates and to be efficient, coupled with step out wells and things to delineate. So when you pad drill, what we do is we'll drill the wells and then we complete them all at the same time. So it's a little bit lumpy that way, which is typical of all the shale plays out there. But with the guys that are focused, they know where we are and there will be, March would be a straight line but I feel comfortable and confident we'll hit our $180 million to $200 million in the Marcellus net and we'll get our 12% growth for the year corporately and do it with a great cost structure. Ron Mills – Johnson Rice: And then lastly, the Granite Wash play, you outlined in your operational portion of your release, that's obviously a different play than what a lot of other operators are talking about in that area. What kind of running room do you have I guess along Leo's lines in that Granite Wash vertical play?

Yes, our play is different. It's a good point. That's why we put a little color on it in the release. The wells are on the order of $1.2 million on the order of 1 Bcf to 2 Bcf. And importantly there is an oil component. IP is again about $2 million per day, 50 to 100 barrels of oil per day with that and very importantly per day the gas of 1,240 Btu. So you get the oil up and you get the oil revenue, also your gas price of 1.24. So that's the huge plus. And very low risk. The other part about a lot of our areas, particularly the Panhandle but as well as our Stron [ph] areas as well, they're in fact pay areas and I'm just talking about and I think every one of those St. Louis wells we've drilled so far, they are up full pays, and with our Granite Wash wells, a lot of time to catch other plays as well. Stron [ph] well is the same. They're up all full pays with those. I'm just talking about the reserves in the main horizon. So it's good to be in areas that have stacked pays, a lot of hydrocarbon in place with a high quality team that just does a great job of continuing to get more and more out of those order properties. Ron Mills – Johnson Rice: Thank you very much.

Thank you. Our next question is coming from the line of Mr. David Heikkinen with Tudor, Pickering & Holt. Your line is now open. You may proceed with your question. David Heikkinen – Tudor, Pickering & Holt: Thanks guys. Just wanted to get into firm transportation and just the thought of taking gas into Canada as we have seen some proposals in that direction and your willingness to try to think about opening up new markets for both gas and then ethane as well as the propane side.

Well this is John. Let me – I'll talk a little bit. Then I'll let Jeff and Rodney chime in a little bit. Again, back to the Marcellus, we've been thinking about kind of markets and where we want to be for a number of years now and we've got a great team in Pittsburg, very high quality team that's been in the basin for many, many years. That is directing us on the ground for us and a couple of things. One, just picking the right partners to do the midstream on and I think we've done that feel very good about it. We're not burdening our capital or our balance sheet with those – they're paying for and ultimately we'll a fee, transportation and compression fee to get those volumes to the biggest pieces of the pipe. Once you get to the get to the bigger pieces of pipe and the good news with that is there is a lot of big pieces of pipe running around in Appalachia. I think five of those seven largest gas pipelines in United States went right through the Marcellus shale play. So you've got the big tow roads. So it's really a question of just building the feeder roads onto the tow roads. That's much different in the Barnett where we had to build several big tow roads to get it out of the Fort Worth basin. So that's a plus. As you think through that, we have taken some firm transportation of several pieces of pipe. Our strategy again is simple, is that we want to be able to have flexibility and move our gas to different areas in Appalachia. We don't know like a lot of people where all the gas bottlenecks are going to be over time. So our idea is to build in flexibility by buying firm transportation that gets us a different delivery point where we can then deliver gas. If you think about longer term, the Marcellus drills out like a lot of the people think. There is going to be some gas-on-gas competition within the basin. So what you want to do is you want to divert gas and have firm transportations on different pieces of pipe, big pipes so that you have flexibility in terms of how you market your gas and what kind of premium the NYMEX are getting to different in different city gates and that's what we've done and we've brought some firm transportation on a number of different pieces of pipe. That being said, I think you've got to be really, really careful about firm transportation in that it's a little bit like office space. These that don't have enough at any one point in time, either they have got too much or you don't have enough. The perfect example of that is the Barnett Shale now and that there is several larger producers in the Barnett that firm transportation on a big pipeline that goes over to a cartage and I think they are paying $0.60, you buy it in the open markets for more around the $0.05 a dine, $0.70 [ph]. So, you can't have too much and it's hitting that balance between having the right amount and then the doing the other thing. The other thing that we have been doing, again we have been productively doing it for several years, is reaching out to some of the bigger users of gas in the basin and developing relationships with them, because some of them have firm transportation and pieces of pipe as well and so we have entered into transactions with them to deliver gas on a firm basis to their firm transportation were quite frankly they are paying for it. Now they are making us obviously there is arbitrage here that we are trying not to have them jam us with the whole amount, but again we have developed relationships there as well. So, again this kind of a high level I think simply we have really seen it through this. David Heikkinen – Tudor, Pickering & Holt: High level as you think about that for a basin that you are dominating some regions, and what is a good percentage of 400 million a day in a year-and-a-half that should be firm versus not – I am trying to think about – you're going to be one of the capacity shippers, so just trying to get an idea how important that is going to be to you.

Well I think we would want I mean again that's a rough question, but we would want at least half of your gas to be on firm and what we also want to do is develop relationships with these other big users of gas out there. What's happened in the basin and I am getting into the weeds a little bit but I think it's important and then historically the basin never, another producers in the basin ever produce large quantities of gas that some of these big end users could use. So, they want to these marketing companies are aggregate and the gas to them. That's all changing now and now they are coming to our range and some of the other big players in the Marcellus again be able to deliver large quantities of gas. So, and still are going through some of the aggregate is not even go directly to the end users and I actually like it because they get a much more of a connection and where the gas is coming from and they can quite frankly, because to some degree you are cutting out the middle-man, you can get better deal off of your gas on both sides of equation. So, I think it's a combination of having your own firm transportation but also having the relationships in the contract for some of the big users. Again it's a portfolio effect and then we will have some of our gas uninterruptible because again you don't want to have too much firm transportation. So, I think it's a portfolio, understanding where the end users are and the other thing is that marketing gas in the Southwest is much different than in the North East. The Southwest has a lot more pipeline infrastructure than the North East, especially the gathering side and that's where Rodney and the team up in Pittsburg have done a terrific job of really taking through that and putting us where I think is in a superior position.

From a simple point of view it just has a big advantage still versus gas and the Rockies or gas in the Gulf Coast or in South Texas or wherever it may come from and you don't have to pay the transport, it's the biggest markets in the U.S.

,: : David Heikkinen – Tudor, Pickering & Holt: And then can you talk some about the JV side and to make an accretive deal one of the best ways to do that is to figure out acceleration and does that lean you towards an operator that actually would be picking up – you won't to want give up operator ship so – or do you or where you could actually – they could bring rigs to part of the play or something that's not going to be as important to Range or is it just purely the financial that comes in and gives you the capital to allow you to double the rig count or really do an acceleration of well count?

I think every deal is different and I think, we have talked both sides of that equation. People who just at least an argue and their main asset is money and then we talked to others that are dying to get into play there are very technical competent or quite frankly we're already in the play just want a bigger position and so we talk to both sides and continue to think through those and I think both of those are interesting in that regard I think you have hit the nail in the hammer. Obviously to the extent that we are looking forward to just money that's a different JV partner to the extent outside of the some of our core areas let's say we have got what I would call some fringe acreage that we could pull together with an operator that we have a lot of confidence then yeah it would make sense and argue to go ahead and take that acreage pool it with them and then must let 13 developer. As soon as – as long as our team had some kind of input into how you drill the wells and how design them, Whose drilling rig it is and that kind of stuff I could care less who is land team is putting together the units is really not all that important. It's really is how you drill the wells and design it and what not, so again I think both of those are different and its and our team we sit around for hours and hours and hours discussing those exact points. But why not let Jeff kind of bury in on that as well.

Exactly let me bury in a little bit, if you look at it we have run a number of cases looking at our developing our acreage position from now really through depletion. We run a number of scenarios of faster flow in between joint venture all kinds of different options and what we think maximizes our share price because that's what it is all about is doing good job be a good storage for the shareholders of which we are totally aligned with is because that's where the bulk of our network is. But to be specific the path we're on now we look at that constantly and periodically to optimize this. We are currently at 13 rigs by the end of this year we will be at 16, by the end of next year 2011, 24 and in our IR material we say the full development will be 50 plus rig but I mean if you look at the trajectory of 13 now going 24 to be simplistic about it cost 48 or doubling it again but potentially its early and we haven't said that yet and there will be a function of lot of things. We are along a path that we think generally it's a tremendous NAV on par or better than the thing that you see with some of the recent market like John said if you use the market transaction of a $1 striker you can pack to it like share prices more than double where we are today. You can calculate any devalues that are significantly high with that trajectory, so we are on high point on that thing, we are not on a full page but however we will look at any point in time are we going to be better by JV, we are doing with Southwestern did a few years back selling a piece off or partnering on some of our current acreages, where that might be fringed us, it might be core for somebody else. We will look at all those opportunities because clearly we want to pack them on values of our company. David Heikkinen – Tudor, Pickering & Holt: As we look at acreage values versus the joint ventures, for your assets you can get values that are 2X pretty easily what the joint ventures have been done on a value per acre and that acceleration case is probably the most compelling thing that we see in the Marcellus particularly given the size and scope of plays, why it is so important. Thanks, guys.

David I think just to reiterate, the one thing I would like to just put out there for everybody is there has not been any material acreage JVs done in the wet gas area and if you just think through the economics in the wet gas area and in today's economics even using the NYMEX curve for ten year for both oil and gas. Your acreage values in the wet gas area when you run the numbers and thus coming back and view all the stuff and all the hocks pocks and divide and whatever you want to call it. It's substantially hard, so you really need to careful when you are looking acreage values in the JV deals to think through kind of what makes sense in valuations when it comes to the wet gas areas versus the dry gas. So, that's my, I will get off the soap box and will get to another question.

: Dan McSpirit – BMO Capital Markets: Gentlemen, good afternoon, and thank you for taking my question. We have observed off late here gas companies chasing the oil story by buying properties in places like South Texas. Can you share your thoughts on this trend whether or not you think it is too late for some of these companies to change their stripes and if it is not too late, do we see range do the same to diversify its asset base at least in terms of the hydrocarbons produced or is that just a ridiculous thought?

Jeff let me start with some technical thoughts on that and then I will turn it over to John for more global thoughts. One when you look at range, one of the advantages we have is – we have discovered what maybe the largest gas field in the U.S. and now we have the dominant part of it plus we have maybe the best economies because of the wet gas part. Now, when you look at the growth opportunities we have and with that in passing 600 wells from the Southwest is de-risk over 12 or 13 piece to it already, with that kind of inventory in hand de-risk over 600 wells and like John said our first well was back in 2004. We are saying that we are going to be at 180 to 20 this year, 360 to 400 end of next year and with that kind of volume of 12 pieces with the opportunity that could be easily doubled at. I believe that in time we will break the Bcf to 2 Bcf per day. What I believe we have the best economics of almost any play out there particularly any gas play and again we had in liquid. So, we are in a great position, we don't have to chase things I think get our growth and get it at low cost. So, I think we have got a lot of multi-year baked in low cost growth of which we are ramping up rapidly approaching 50 rigs in order to capture NPV. So, that's a comment one, comment two would be, a lot of people are and we have been talking about this and we have a South team, that's out there looking at different plays. A lot of people we are talking about getting into oil field, I am talking pure oil shales not the Balkan, Balkan doesn't count because they got conventional reservoirs and you may extend it. But the industry now is shifted to hey we are not going to not only going to look at the dry gas shale's which were a breakthrough a few years back to the wet gas areas which are hot now and again we are thinking in some of the shale's there is no wet gas and some of the shale plays out there, they are Fayetteville or Haynesville they are basically dry gas point. So you can't chase it everywhere, you have to be in the shale which has that and you have to be in the – and Illinois has it but has tight quality rock in the right part of it which the Marcellus does. : In the long run it doesn't matter, what matters is comes to flow equations with the safer that curve going to be over a year or two or five and 10 years and how much do you have to pay out from going forward and the industry hasn't shown you that in a big way that they can make that economic. It may work, it may not work I mean at least we have a lot of low risk expecting things that we think we can drive that up for years to come. We will be opportunistic, we will look at plays but we are not going to jump at the latest fad I think like a lot other companies have done which may or may not work, but I am just saying from a technical perspective in my opinion, you have changed the risk profile when you are going from gas to oil because if it's got for the oil and the order of magnitude higher than gas which is going to make it lot larger long term to flow through that low quality rock. So, that was my comment so far I will turn it to John for the more global stuff.

: If you think about it kind of simplistically, if I were out in the acquisition market today and going to buy reserves what would I buy. I got to tell you I would then buy gas, not oil because I think oil is trading at the high end and gas you are getting at trading at the low end. Again I think some why Exxon bought XTO. They thought they were buying a resource base that was at the lower end its long-term of view of gas I mean prices and the NYMEX curve, I am not talking about this year but if you look at NYMEX curve for 10 or 20 years it would suggest that. So, if I am buying reserve today I am buying natural gas versus oil. On the other side if I had a big oil field and if I had two places to spend money and one was oil and one was gas I would simply run the economies, figure out which one is going to generate the highest return over the period of time and do that and I have the same company and our friends in Newfield shifted some of their capital dollars over to existing oil fields they own and are seeing up that development. I think that is very prudent and I think Newfield is a great company and I think it makes absolute sense, where I think what Jeff said is absolutely right though to jump out of lower risk projects and to jump, push your money in through dramatically higher risk projects chasing oil can be a two edge story. So, if you are good at that and it works you are going to over perform. But if you don't then you are going weigh you're underperformed and so therein lies is the issues is that there is the risk associated with that strategy. I love the strategy because what I am hopeful for is all these guys do jump in the oil that, the natural gas rig account continues to move down. We had some sanity comeback into the market last week and some natural gas rigs decline, hallelujah. So, I am hopeful as that trend continues, more people jump in the oil and shift things that natural gas supply will come down and that we will see gas as far as move back up. With the combination of stronger economic growth, more electric generation in the U.S. being developed with natural gas versus the nasty stuff we are using today and the reduction in natural gas rig count then you will see prices move back up and maybe not as long as some but I have been in this business for a long time and I keep on saying that care for low prices as low prices. But and I think energy will readjust these gas prices and especially I think one point is important is as you look at the hedges, the industry has in place today for 2010 the gas hedges haven't seen the number, we haven't done analysis specific but I have read some analysis by analyst. We are about 70% maybe even 75% on hedges for 2010 or actually for first half of the year. So, as those hedges roll of here in about two months then you are going to see the rig count even fall down more aggressively that would make sense to me. Again one of the reasons why we hedge jumped from 23% to 51% for 2011 is I am a little concerned with the available access of capital assets, the ready access of capital for just about anybody that wants in our business. Obviously just a little concerned that there may be that market may stay open longer than I think it should and that some companies will jump out there and grab some capital and continue to drill in an environment that they wouldn't normally if they didn't have that ready access to capital. So, I think that's kind of gives you our summary in terms of how we view all that, doesn't mean we are right. Our view of it is like Jeff said we found a giant gas field, it has really good economics even at 450 gas, so and we think we substantially de-risk it. So, we don't have a great desire to have to jump out and do something else. We're making good returns to our shareholders and we think we will continue to do that even if gas stays in to $5 to $6 range for a long time. So we feel good about it, so, I think you will see us not do anything that's high risk if I should put that way, where is an acquisition or a new play idea.

Let me add one another technical comment, long answer to your question but it's an important question is and I just want to caution people on IP's, a lot of people talk about IP's are jumping to oil shale, I will use Eagle Ford for an example, and if you look at the oil part of the Eagle Ford very few wells in there and there are couple of high rate wells and as you come up in Eagle Ford from the dry gas window to the wet gas for the oil you go basically from a true shale to basically a carbonate and it's a black looking rock but when you look at the mineralogy's it's really a carbonate. And when you come up into the shallow part in fact there you have the Eagle Ford, (inaudible), and then Austin Chalk right and a fairly narrow package. When you look at those early wells and time will tell clearly you can get some high rates if you get into fracs there and now against the Chalk in fact some – like I said when you move the Eagle Ford out in some of the shallow areas basically it's a carbonate which is like things what a Chalk is and same family. So, there is no question if you get into the good fractured area you can get good and as it relates the question is long-term. Once you drain the fracture system what's the matrix going to feed into the fractures there and that's really going to tell the tale on what's the rate of return and the economies to your well. So, again those things may work, they may not work but I am just saying it's a different risk profile and the good news is given the inventory we have in the economies of our project even down to extremely low gas prices we can just stay focused on driving Marcellus up and keeping our cost down and improving our wells. Even as 250 gas and $60 oil, our Marcellus oil and wet gas areas in Southwest still generate a rate of return of about 35%. So, that we will stay focused on. Dan McSpirit – BMO Capital Markets: Got it. John and Jeff, I appreciate your thoughts. Gentlemen, that's all I have.

Thank you, Ladies and gentlemen this concludes today's question and session. I would like to turn the call back over to Mr. Pinkerton for his concluding remarks.

: :

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