山脈資源 (RRC) 2010 Q1 法說會逐字稿

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 speakers' remarks there will be a question and answer period.

At this time I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon and welcome.

Range Resources reported results for the first quarter 2010 with record production beating the consensus numbers and continued to execute our business plan with improving unit cost while navigating this period of challenging commodity prices. The first quarter marked our 29th consecutive quarter of sequential production growth. Although we're encouraged with our resource space to continue to grow production and reserves in the future, we're 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 would 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 non-GAAP measures of cash flow, EBITDAX, 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 detailed information of our current hedge position by quarter. Second, we will be participating in several conferences in May. Check our website for a complete listing for the next several months. We'll be at the Calyon Energy Forum in New York on May 13th and 14th, the Platts 3rd Annual Midstream Development Conference in Houston on May 21st, and the UBS Oil and Gas Conference on May 27th. And then our stockholders meeting is being held in Fort Worth on May 19th. We hope that each stockholder has received their proxy materials, and we urge each stockholder to vote for the proposals 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 drilling program was on schedule throughout the quarter as we drilled 72 wells. We continue to be very pleased with the drilling results and despite the lower prices we're generating attractive returns on capital. Currently we have 22 rigs in operation. The 12% increase in production was more than offset by a 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 a per unit of production basis nearly all cost categories were lower than the prior period, and in particular, direct operating costs came in at $0.73 per MCFE. This is 22% lower than the prior year period -- quite an achievement. With regards to our Marcellus shale play, significant headway was made in the quarter as we continue to drill some fantastic wells, fill in our acreage position, 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 3,300 wells and over 13,000 leases, so I am really pleased that we were able to get it closed so early in the year. All in all I couldn't be more pleased on how much we accomplished in the first quarter. I think it is 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 review financial results.

Thank you, John. The first quarter of 2010 in some ways looks a lot like the first quarter of 2009. Production reached a 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 -- being sharply lower. Peering a bit deeper into the numbers, however, reveals a stronger operating performance than last year, with significantly lower unit operating costs plus the balance sheet benefit of having sold most of our Ohio tight gas sand properties at the end of March. Quarterly oil and gas sales including cash settled derivatives totaled $233 million, down 6% from last year's revenue figure of $248 million. 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 2009, with cash flow per share of $0.92, $0.02 above the analyst consensus estimate of $0.90. EBIDAX for the quarter was $176 million, 5% lower than the first quarter of 2009. First quarter 2010 cash margins were down 18% from last year at $3.49 per MCFE compared to $4.25 per MCFE in 2009. There are a few extraordinary revenue and expense items flowing through the financial statement this quarter starting with a pre-tax unrealized mark-to-market gain on our hedges of $46 million and a $69 million pre-tax book gain primarily from the sale of our Ohio properties. On the expense side we have $7.9 million in severance costs from the Ohio sale, along with a $6.5 million low gas price induced impairment of a Gulf Coast property. Lastly, as our stock price declined slightly during the quarter, we recorded 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 mask some of the recurring good news found deeper in the expense lines of the income statement and first up on the good news list as John mentioned is a cash direct operating expense reduction per MCFE of $0.23 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 $1.05 per MCFE in mid-2008. The news gets even better when looking ahead into the second quarter of 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 costs per MCFE by another $0.05. That would bring it down to the high $0.60 range. Production taxes have drifted lower with a 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 are 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. That reflects the shift from short-term floating rate debt to long-term fixed rate notes 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 bearing fixed interest rates and the cash on hand from the Ohio sale available to fund our 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 primarily to higher delay 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 seismic and delay rental increases before falling back to the $10 million to $12 million per quarter range the rest of the year.

Depletion, depreciation, and amortization per MCFE for the first quarter was $2 -- I am sorry, $2.12 -- and that's compared to $2.25 in the first quarter of last year. The figure consists of $1.97 per MCFE in depletion expense and $0.15 attributable to depreciation and amortization of our other assets. Our DD&A rate has declined considerably from the $2.34 MCFE rate for all of 2009. The lower depletion is primarily from the continued favorable performance of our Marcellus wells and while the DD&A rate will fluctuate quarterly going forward with our production mix, we anticipate a DD&A rate in the $2.15 to $2.20 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 -- that's down $7.2 million from last year. Investors may expect to see an abandonment and impairment figure for unproved in the second quarter of approximately $12 million to $14 million.

Range incurred $49 million in deferred taxes for the quarter, but paid no cash taxes. Following the filing of our year end federal income tax return our NOL carry forward is now $322 million. Our effective tax rate the rest of the year is anticipated to be 38.5%, with all cash federal tax payments deferred. Cash state taxes will approximate $1 million per quarter. Now, while we're on the subject of taxes, you may have noticed that had we have elected to place the bulk of the Ohio asset sale proceeds in a like kind exchange account. With the interest rate on our bank facility hovering around 2%, we felt that the negative carry incurred, represents a small price to pay for the ability to possibly defer some or all of the estimated $255 million gain on the Ohio transaction. The cash is completely unrestricted, and we may move the funds out of the account any time we desire.

For the remainder of 2010 Range has approximately 77% of its gas production hedged 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 hedged, 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 hedged using collars at $75 by $93.75 and approximately 5,200-barrels per day hedged in 2011 with a collar of $70 by $90. Besides the previously mentioned asset sale proceeds parked in cash on the balance sheet, there are several other balance sheet items worthy of mention. First, despite significant assets sales, on March 30th the Range bank group reaffirmed the existing $1.5 billion borrowing base through our next determination date of October 2010. We elected 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. Second, unlike last year when we were out spending 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 or transaction sale risk from our 2010 capital plan.

The benefits of disciplined spending and a completed asset sale may also be seen in our debt-to-cap ratio. Netting the cash balance against our bank debt produces a net debt-to-cap ratio at the end of the quarter of 36%. This places our leverage below our targeted 40% ratio and it compares favorably to the 43% ratio at the end of 2009's first quarter and the 47% ratio in 2008. A 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 declines. The first quarter was also a strong quarter strategically, with the Ohio asset sale completed, over $1 billion in liquidity, and our hedging program delivering cash flow certainty during periods of low prices. Overall we are entering in 2010 on a much firmer footing than 2009. Last year when we started the year, we were shedding rigs and reducing activity to fit the 2009 budget, while commencing -- just commencing -- the sale of our Fuhrman 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 to review our operating activities. Jeff?

Thanks, John. I'll start the operations update with the Marcellus Shale.

Our strategy at Range is and has been growth at low cost. Range's Marcellus production has the best economics of any large scale repeatable gas play in the US. There are basically four reasons for this. The first is that this discovery is in the Appalachian Basin which is in close proximity to the best gas markets in the US. Therefore the gas produced here is advantaged versus other gas in the US. It doesn't have to be transported far to get to the end-user. Second, not all areas in the Marcellus or any other gas play for that matter are equal. To have the best economics, you 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 and combined with the way in which we have 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 the 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 are so good -- perhaps the best in the Marcellus play -- is 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 where gas prices and oil prices are, if you have processing, which Range does, through our contract with MarkWest, this is a huge benefit. If 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 doubles 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 have drilled in the form of zero time plot by program year. Importantly, we have continued to improve the quality of our wells year after year. Although other shale plays have the same characteristics, we are unique in that our play was economic very early on. Other plays required a lot of time, long laterals, and a lot of frac stages to make them economic. The fact that the Marcellus didn't 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 have also adjusted the expected cost of our development wells in southwest Pennsylvania from $3.5 million to $4 million per well. This increase is a direct result of going to longer laterals and more frac stages. The bottom line is a better rate of return, lower finding costs and better efficiency.

The buildout of the infrastructure continues on plan. Cryo capacity will be increased by MarkWest from 155 million per day today 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 today to 65 million per day by late 2011. Dry gas gathering and compression capacity in the northeast through our PVR contract, will come on line late this year and will be 120 million per day by late 2011. In aggregate, by late 2011, we'll have the infrastructure capacity of 575 million cubic feet per day. As you can see, we're on track to reach our Marcellus production target of exiting this year at a net rate of 180 to 200 million per day and exiting 2011 at a net rate of 360 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 or in the works, we're well-positioned to meet or exceed our plans for the Marcellus.

We 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 base and the first upper Devonian shale well in 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 horizon by year end.

In regard to our 2010 budget, 77% of our capital is going under the Marcellus Shale. That's because the 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 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 have dropped from six to eight rigs about 15 months ago, to one to two rigs today. The projects in both areas have good rates of return at today's prices. Importantly, we'll continue to monitor them and look at the rates of return on a realtime 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're primarily targeting a new play that we discovered, the 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. We're in the early stages of the play. We're also drilling some Granite Wash wells and a couple of horizontal Mississippi and oil wells in existing fields that we have in the Texas Panhandle and Oklahoma. At Range our strategy is to grow production with one of the best all in cost structures in the business and to build and high grade our inventory. In addition to adding high quality plays like the Marcellus, Nora and the Barnett to our portfolio, we'll have sold out of the Gulf of Mexico, Ohio, New York, Furhman-Mascho and other fields. The net result is shown on our website in our latest IR presentation.

Since 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. Put simply, since 2007 we have decreased our well count by 57% while increasing our projected production by 52%. Bottom line we're a much more efficient Company. The combination of adding higher quality plays and focusing our people and capital there while selling relatively high cost, low growth areas has led to better production and 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 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're 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 reflects the sale of the Furhman-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 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 streak of 29 consecutive quarters of sequential production growth will come to a halt. As I have said in the past, I will not be disappointed to see the streak end, if it was in our best interests. Clearly the Ohio property sale was in our best interest, given the terrific price we received.

For the year we still anticipate hitting our production growth target of 13% even after accounting for the property sales. Now that we have closed the Ohio property sale, I will take a moment to look at the impact of our divesture program. Over the past three years, we have reduced our well count by roughly 6,000 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 more mature higher cost properties, we were focusing 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 time period -- over the same three year period that we saw our well count decline 57%, our production rose 52%. As a result, Range is a much more efficient Company. We like to say we're doing more with less. By less, we mean less wells, lower finding development costs, lower operating costs, et cetera.

The first quarter results partially reflect this lower cost structure which should continue in subsequent quarters, especially in the second and third quarters after the Ohio sale is -- the Ohio properties -- are no longer running through our income statement. Over the medium term this will have a significant positive impact on our NAV per share. This is critical to generating attractive returns in a low gas price environment. In addition, by having fewer wells and properties and a 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 fewer 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 that the timing of the Ohio sale was important. Given 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 of 2010 versus later in the year. Conversely, we did the opposite with regards to our 2010 capital program, in that we intentionally designed the program where less capital would be spent in the first and second quarters and more capital in the third and fourth quarters. As a result, in the first quarter we spent only 20% of the 2010 capital budget versus 32% in the first quarter of 2009. The combination of getting the 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 relates to our capital efficiency. In the past several years we spent considerable capital in the Marcellus play without seeing much of a return. Beginning in 2009 this all changed as 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 for the Marcellus ramping up as well as the full benefit of the asset sales. 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'll achieve our 2010 production growth target as well as reaching our Marcellus exit rate of 180 million to 200 million a day by year end. Because of the terrific infrastructure progress we're making in 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 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 to 51% of our anticipated production at a floor price of $5.73 and a cap of $6.83. Our [far teels] are fairly simple in we wanted to lock in cash flows so we could fund our capital program for 2010 and for 2011. Like many of you, I am concerned about the number of rigs drilling for natural gas in the US. I am also concerned with the ready access to capital that the industry enjoys. While I am convinced the industry will ultimately adjust capital spending to fit gas prices, we are taking the timing of the industry response off the table by locking in floors 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 of late. Clearly the Anadarko Mitsui transaction and the Atlas Reliance transaction are exciting to see. If one were to apply those valuations to Range's Marcellus acreage position, one can justify a Range stock price more than double where it trades today. This is great news in that others are beginning to understand and pay for the superior economics that the Marcellus shale play has achieved. We think over time as more wells are drilled and more of the play is derisked, that the acreage joint venture prices will increase. I remember many people saying Chesapeake's deal with Statoil at $5800 per acre was terrific and that Range should consider the same. Just fifteen months later we have seen Mitsui and Reliance pay over $14,000 per acre or roughly 2.5 times what Statoil paid. While Chesapeake, Anadarko and Atlas had valid and company specific reasons to enter into their joint ventures, we believe joint ventures are what they really are -- which is a sale of assets. As we have said before, we prefer to sell our lower quality, more mature assets, not our higher quality, higher growth assets.

Most importantly, we believe that as the Marcellus continues to be derisked by more drilling, that the acreage prices 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 being said, we will consider joint ventures or 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 be derisked. Additionally, we believe we have the highest quality acre position in the play, the best infrastructure arrangements 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 TCF -- 30 TCF -- of resource potential which equates to nearly ten times our existing proved reserves. We have obviously a cost structure after the asset sales that is going to be very, very low. So while we're excited about the growth potential at Range, we are intently focused on delivering each quarter. The first quarter of 2010 is a shining example of this commitment by all the employees at Range.

With that, operator, let's open the call up for questions.

(Operator Instructions) Our first question is coming from the line of Mr. Marshall Carver with Capital One Southcoast. Your line is open and you may proceed with your question.

All right, just a couple of questions. The St. Louis and [Stron] areas where you drilled some successful wells, how many locations or net locations do you have in each of those areas?

Well, the St. Louis is very early for us, but we've got a good acreage position we're building. We have close to 40,000 gross acres, and we think approaching 250 potential gross locations, so it can be very impactful. We're going slow. It is early on, but so far we're encouraged by what we see.

In particular, it is just great economics -- $1.3 million for a little over 2 BCFE coupled with the fact you have an oil component, the wells have come online at 2 million to 50 to 100-barrels of oil per day, the gas is relatively rich even after that 1080 BTU, so we're excited by the play. It is a play our guys generated up there. It is early on.

And then in the Stron, not as much potential, but when you look at the acreage you're having, things that we could acquire and again it is early on in the play, but we drilled several great wells, IP's of 300 to 700-barrels per day, rich gas with it. In aggregate, it could approach 100 wells over time if we continue to successfully drill and acquire a few things we see. The guys are doing a good job not only of driving up production in the Marcellus and making better and better wells and better economics and keeping our eyes on the ball there. But the guys in the other divisions are extracting a lot of values out of our old properties and old areas.

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 open. You may proceed with your question.

John, I guess you just mentioned you would potentially 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?

Leo, it is a great question. I appreciate you asking it. Maybe I wasn't as eloquent as I should have been, but historically our strategy has always been at Range we're going to do what's in the shareholders best interests. And therefore I didn't think -- and our team didn't think -- doing JV's at relatively low prices made any sense because as you said we really didn't need the capital to exploit it. As things move along in the play -- and clearly Chesapeake did their deal at $5,800, 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 will be paid will become closer to what we think fair value is. And so we'll continue to monitor that and if we think we're getting something that we believe is in fair value and it is NAV accretive, when you take the time value into account, we think that is in our shareholder's best interests, and we would look at it very closely and consider that and take it to the board and get their input.

So again it all comes back to driving it up our NAV per share, so if we can do things that don't screw up the balance sheet or screw up the simplicity of the Company materially, we'll look at those for the best interests for the shareholders, and we'll move forward with that. As you can imagine with all of the different things out there, we've had lots of discussions with lots of people. We'll continue to have lots of discussions with lots of people, and we'll do the right thing.

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?

We have. What we talked about on the last quarterly call is we drilled them and logged them and we're encouraged by what we saw based on ECF logs and such and shows. We've now drilled and case tested them and in the press release we mention we're going to be hooking up, so clearly we found gas. But in general, with any specifics we're going to hold that tight. It is very early on in the play.

Importantly, I think -- I just want to re-emphasize we think the most prospective part for upper Devonian shales is primarily in the south and southwestern portion of the state. That's where they have the right thickness and rock properties to make them prospective. When you look at all the various things that make shale plays work and in the Utica we think it is primarily prospective on the western half of the state. The good news is we have 1.3 million acres in the state -- primarily all in Pennsylvania of which h 600,000 acres are in the southwest portion of the play, so a lot of our acreage is prospective for that, it's a big upside. We're encouraged by what we see early on.

It is early. We'll drill a couple of more wells probably by the end of the year and like we were with the Marcellus a few years back, we'll keep it relatively tight and make sure we capture that for our shareholders. The good news is a lot of it is stacked on our existing acreage. So we captured a lot already and obviously there would be things we want to fill in.

Okay. One other thing. You mentioned in your press release as you're taking your EURs up on your Marcellus from 3 to 4 Bcf to 4 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, we have again 1.3 million-acres basically within the fairway, 900,000 of that is high graded, and it is really well-positioned. I mentioned before there has been over 600 wells in the southwest -- Range wells and others, both vertical and horizontal -- that have derisked a huge portion of the acreage in the southwest. The other 300,000 acres in the Northeast is predominantly a laydown where Anadarko and Mitsui did their deal. We haven't put it out specifically but a lot of it Lycoming plus or minus a county on either side -- Bradford, Lycoming, down in there -- so we feel given the industry's results to date that's very high quality acreage as evidenced by the quality of wells and evidenced by the deals that John mentioned.

Okay. I guess that last question for you guys obviously your direct operating costs LOE looked great this quarter. Sounds like that's going to drop again next quarter. Can you give us any ballpark as to where that can go this year?

I think Roger mentioned it is going to drop another $0.05 or so, so it will be in the mid-to upper $0.60 range next quarter.

Okay. Thanks a lot, guys.

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

Good morning, guys.

Good morning, Dave.

Or I guess afternoon. I apologize. Let's see.

Just thinking about your drilling activity over the next two 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 -- obviously the balance -- out of the southwestern portion?

We can guide you somewhat. Through the end of this -- we're not going to have the Lycoming County stuff -- the northeast stuff on until toward the end of this year -- so basically in essence almost all of the 180 million to 200 million per day net -- and I want to emphasize the word net -- will be coming from the southwest and predominantly from the wet gas portion, almost all of that. When you project on into next year, a lot of our drilling is still 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.

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 am gathering that there is -- relative to the announcements you made about Stron and other areas -- that we should be anticipating an uptick in the liquids production as well. Can you give us some additional color there?

That's very intuitive. If you look at the delta change in the liquids, our liquids production is going to go screaming up this year and next year. Next year for example we think the liquids production will be more than twice what oil production is and be heading north from there -- so pretty intuitive question. And again I think it really circles 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 and a high price oil environment, the benefit of the being in the wet gas is dramatic. Again, it is part of the method to the madness in terms of how we develop our acreage position and what we're doing and why we're doing what we're doing is all encompassed in all of that.

So if I look at percentage hedges right now and I tried to project growth, I should just think the same 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 am not following you completely. I just -- it is really hard to hedge liquids. Most people that hedge liquids 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 focus on that, especially given where it is today. If you want to get into the details of the oil versus the NGLs, I suggest you call the great Rodney Waller and he can run you through all those detailed numbers after the call.

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's seeing that same deviation in value and obviously wants to capitalize on it?

Yes. Again, that's a very intuitive question and 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 amount of liquids is going to be generated from the Marcellus when you look at the entire play is 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 MarkWest is their expertise when it comes to liquids and how you distribute the liquids up in the northeast, and to give you an example within twelve months we'll have a propane line in and we'll be selling our propane 12 to 24 months through a pipeline. We're putting a rail spur in. So instead of trucking the liquids we'll be rail-caring the liquids out, and the good news is most all of that will be used in the northeast. There are some very good markets in the northeast for all of that stuff. We have analyzed that and don't see that as being an issue. In fact, one of the good things that's happening is on a relative basis on liquids and everything we're actually getting a higher price for the liquids coming out of the Marcellus than we are in other places because the market is so robust in the northeast versus the other parts where there is more competition and more liquids coming onto the market. It is how we look at it on a 50,000 foot 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 dominates that wet gas part which is an advantage we have. It is a big part of what we have. It is a small part of the total play for the industry.

One thing I can do is direct to you probably MarkWest's website. Randy Nickerson made a presentation last week at Doug East Marcellus Midstream conference in Pittsburgh showing what the total demand of Appalachian products were for each of the components -- both in the winter and the summer markets -- and showed what our production would be that it is going to be largely maybe a third of what capacity could possibly be in the next three to four years. So, therefore, I think the misinformation 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 liquids out of the Gulf Coast and pay a transportation charge for it, we can compete very competitively with those because we can avoid the large transportation charges coming out of the Gulf, so it ensures a ready market for us and people very willing and able to take that as long as we can give them consistent quality and consistent quantities.

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 and Rice. Your line is now open. You may proceed with your question.

Just a question on leasing and lease expirations -- I know you have plus or minus 15% of your budgets going towards leasing. Can you provide 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?

Ron, this is John. Pretty good game last night.

Yes. I think the fix was in.

Great question, Ron. Let me start at high levels and I will work down. We haven't been buying what I would call trend acreage in the play for two years. What we have really been doing -- and the reason is because we drilled a bunch of wells and we drilled our first completed our first well in '04 and we drilled a bunch of wells in '05 and '06 in areas that we felt were really, really, really perspective. So we immediately started buying acreage in there for $50 to $100 an acre and it moved up to $500 an acre, so most we got relatively cheaply most of them have very low royalty burdens, so we're in terrific shape. What we're doing now, what we have 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 up 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 is -- if you can block up your acreage it really helps dramatically in lowering your cost as you go forward, and it is everything from pipeline costs to road costs to infrastructure costs, all of those costs go down and the economics of the play go up.

Our budget this year is to do a number of things. One, fill in the holes. The other thing is we have a huge acreage position -- 1.3 million acres. We're not going to hold all the that acreage from drilling. So we have to decide each year what do we to want hold, what do we want to let go. The good news is everything that we have wanted to hold this year we have already released 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. Part of the budget is going to go to filling in the holes. The other part is going to be releasing some of the acreage we're not going to get to currently.

The other thing we're doing also is -- I think the industry -- it took awhile for the industry to catch up with us quite frankly -- but there is a lot of companies and a lot of big companies that have acreage that are spread out all over the play and as they drill wells, they start becoming -- they start developing -- their little core areas. So we talked to a lot of different companies about trading acreage and we'll trade 15,000 acres over in one of our core areas for 15,000 they have in one of their core areas, assuming they're relatively equal in terms of quality and royalty burdens and exploration. So we have done that and we're going to continue to do that and it is something that we think again will allow Range -- in a big way and the rest of the industry -- 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 Mitsui and Reliance paying $14,000 an acre for these big blocked up areas. You don't have to pay $14,000 an acre to go out and lease 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 be. 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.

It does. And then I think, Jeff, normally you walk through your production on an area by area basis. Curious if you had the breakdown -- Marcellus versus Nora versus southwest division.

Yes. If you look at the major plays, we're looking at -- we're on track to hit our 180 to 200 in the Marcellus. Today we're approximately 130 million per day net, something like that. In the Barnett we're 120, 125. Nora about 65 million per day. Those would be the top three, and then the rest of it is a lot of legacy tight gas sand or oil production.

And then in terms of the timing of production ramp, particularly in the Marcellus, obviously you will have some come on at the end of the year in northeast Pennsylvania, but in terms of the march from 130 million a day to the 180 to 200 million a day, how consistent is that over the remaining three quarters or are there major infrastructure I guess bottlenecks being relieved at a particular date?

No. The 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 stepout 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 is a little bit lumpy that way which is typical of all the shale plays out there. We're -- the guys are focused they know where we are and we'll -- there will be a march -- will it be a straight line up -- no, but I feel comfortable and confident we'll hit our 180 to 200 million a day in the Marcellus net and get our 12% growth for the year corporately.

Okay.

And do it with a great cost structure.

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?

We have -- yes, our play is different. It is a good point. That's why we try to put a little color on it in the release. The wells are on the order of $1.2 million for -- 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 10000-barrels per oil a day with that. And, very importantly per day, the gas is 1,240 BTU so you get the oil revenue plus your gas price times 1.24, so that's a huge plus. Very low risk.

The other part about a lot of our areas, particularly the Panhandle but as well as our Stron areas as well, they're in stack pay areas, and I am just talking about -- I think every one of those St. Louis wells we drilled so far there is up hole pace -- and with our Granite Wash wells a lot of times we'll catch other pays as well. Stron wells are the same -- there's up hole pays with those. I am just talking about the reserves and the main horizon. So it is good to be with in areas that have stacked pays -- a lot of hydrocarbon in place with a high quality team that does a great job of continuing to get more and more out of those older properties.

Thank you very much.

Thank you. Our next question is coming from the line of Mr. David Heikkinen with Tudor, Pickering and Holt. Your line is now open. You may proceed with your question.

Just wanted to get into farm 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 ethane as well as the propane side.

Well, this is John. I will talk a little bit and let Jeff or Rodney chime in a little bit. Again, back to the Marcellus, we have been thinking about markets and where we want to be for a number of years now. We have got a great team in Pittsburgh, very high quality team that's been in the basin for many, many years, that is directing this on the ground for us, and a couple of things.

One, picking the right partners to do the midstream on and I think we have done that and feel very good about it. We're not burdening our capital or our balance sheet with those. They're paying for it and ultimately we'll pay them a fee -- transportation and compression fee -- to get those volumes to the bigger pieces of pipe. Once you 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 the United States run right through the Marcellus shale play. So you've got the big toll road, so it is really a question of building the feeder roads on the toll road. That is much different than the Barnett, where we had to build several big toll roads to get it out of the Fort Worth Basin. That's a plus. As you think through that we have taken some firm transportation on several pieces of pipe.

Our strategy again is simple -- is 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 to different delivery points where we can then deliver gas to our end-users. If you think about longer term if 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 divert gas and have firm transportation on different pieces of pipe -- big pipe -- so that you have flexibility in terms of how you market your gas and what premium the NYMEX are going to get and the different city gates and things. That's what we have done. We bought some firm transportation on a number of different pieces of pipe.

That being said, I think you got to be really, really careful about firm transportation in that it is a little bit like office space. You either don't have enough -- at any one point in time you either have too much or you don't have enough. This perfect example of that is the Barnett Shale now in that there are several larger producers in the Barnett that bought firm transportation on that big pipeline that goes over to Carthage, and I think they're paying $0.60. You can buy it in the open market for what Rodney, $0.05 to $0.10?

$0.07 or $0.08.

$0.07 or $0.08, so you can have too much and it is getting the balance between having the right amount and doing the other thing. The other thing we have been doing and again we have been proactively 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 on these pieces of pipe as well and so we entered into transactions with them to deliver gas on a firm basis through their firm transportation where quite frankly they're paying for it. And they're making obviously there is -- yes, there is an arbitrage there we're trying to not have them jam us with the whole amount -- but again we have developed relationships there as well, so again just a high level, I think we have really thought through this.

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 -- 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.

I think we would want again that's a rough question -- but I think you would want at least half of your gas to be on firm, and plus what you also want to do is develop relationships with these other big users of gas up there. What's happening in the basin, and I am getting in the weeds a little bit, but I think it is important is -- historically the basin never producers in the basin ever produced large quantities of gas that some of these big end-users could use, so they went through these marketing companies to aggregate and get the gas to them. That's all changing now.

Now there is companies like Range and some of the other big players in the Marcellus are going to be able to deliver large quantities of gas. So instead of going through some of the aggregators now, you can go directly to the end-users, and they like it because they get a much more of a connection on where the gas is coming from, and they can quite frankly -- because to some degree you're cutting out the middle man -- you can get a better deal for your gas on both sides of the equation.

So I think it is a combination of having your own firm transportation but also having the relationships and the contracts with some of the big users that -- again it is a portfolio effect. And then we'll have some of our gas uninterruptible because again, you don't want to have too much firm transportation out there. So it is I think a portfolio, understanding where the end-users are. The other thing is that marketing gas in the southwest is much different than in the northeast. The southwest has a lot more pipeline infrastructure than the northeast, especially in the gathering side, and that's where Rodney and the team up in Pittsburgh have done a terrific job of really thinking 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 in the Rockies or gas in the Gulf Coast or South Texas or wherever it may come from and you don't have to pay to transport it to the biggest markets in the US.

There is some city gates, Washington, DC, Boston, Baltimore, New York City, all of these. If you can get gas there, you're selling for gas for over $2 an Mcf over NYMEX, to the extent you can get it there cheap and not have to pay freight, obviously your netbacks are going to be better, so therein lies the advantage of having gas in the Appalachia basin.

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 rig count or really do an acceleration of well count?

I think every deal is different, and I think we talk to both sides of that equation -- people that just have -- at least in our view their main asset is just money -- and then we talked to others that are dying to get in the play that are very technically competent. Or quite frankly who may be already in the play, just want a bigger position. So we talk to both sides and continue to think through those, and I think both of those are interesting in that regard, and I think you hit the nail on the hammer.

Obviously to the extent that we're looking for just money that's a different JV partner. To the extent outside some of our core areas -- let's say we've got what I would call some fringe acreage that we could pull together with an operator that we had a lot of confidence in, then, yes, it would make sense in our view to go ahead and take that acreage and pool it with them and then let their team develop it as long as our team had some input into how you drill the wells and how you design them. Whose drilling rig it is and that stuff I could care less -- and whose land team is putting together the units is really not all that important. It is really just how you drill the wells and design it and whatnot.

Again, I think both of those are different, and our team -- we have sat around for hours and hours and hours discussing those exact points. Why don't I let Jeff burrow in on that as well.

Yes. Let me burrow in a little bit. If you look at we have run a number much cases looking at or developing our acreage position from now really through depletion. And we've run a number of scenarios -- faster, slower, in between, joint ventures, all kinds of different options on what we think maximizes our share price. Because that's what it is all about is doing a good job -- being good storage for the shareholders of which we're totally aligned with you -- because that's where the bulk of our net worth is.

But to be specific the path we're on now will look at that constantly and periodically to optimized it. We're currently at 13 rigs. By the end of this year we'll be at 16. By the end of next year -- 2011 [we will be at] 24. And in our IR material we say in full development it will be 50 plug rigs. If you look at the trajectory of 13 now, going to 24 to be simplistic about it, call it 48 or doubling it again -- potentially it is early and we haven't said that yet and it will be a function of a lot of things. We're on a path that we think generates tremendous NAV on par or better than the things that you see with some of the recent market trends. Like John said, if you use the market transaction of dollars per acre, you can calculate share price that's more than double where we are today. You can calculate NAV values that are significantly high -- with that trajectory.

So we're on -- my point being -- we're not on a slow pace. However, we'll look at any point in time are we going to be better by JVing or we're doing what [Southwestern] did a few years back and selling a piece off or partnering on some of our fringe acreage with where that might be fringe to us it might be core for somebody else. We'll look at all of those opportunities because clearly we want to maximize value of our Company.

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 is not been any material acreage JVs done in the wet gas area. If you just think through the economics in the wet gas area, under today's economics, even using the NYMEX curve for ten years for both oil and gas, your acreage values in the wet gas area, when you run the numbers and discount them back and do all the stuff, and all the hocus pocus and divide and whatever you want to call it, it is just substantially higher. You really need to be careful when you're looking at acreage values in these JV deals to think through what makes sense in valuations when it comes to the wet gas areas versus the dry gas, so I will get off the soap box and get to another question.

Thank you. We are nearing the end of our conference today. We will go to Mr. Dan McSpirit of BMO Capital Markets with our final question.

Gentlemen, good afternoon, and thank you for taking my question. We have observed of 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?

It is Jeff. Let me start with some technical thoughts on that and I will turn it over to John for the more global thoughts. With when you look at Range, one of the advantages we have is we have discovered what may be the largest gas field in the US and then we have the dominant part of it -- plus we have maybe the best economics because of the wet gas part. When you look at the growth opportunities we have -- and we said in past things 600 wells in the southwest of derisk over 12 or 13Ts to us already, with that kind of inventory in hand derisked by over 600 wells -- and like John said our first well was back in 2004 -- we're saying that we're going to be at 180 to 200 this year, 360 to 400 end of next year, and with that kind of volume of 12Ts, the opportunity we could easily be double that, I believe in time we'll break a Bcf to two Bcf per day -- with what I believe has the best economics of almost any play out there, particularly any gas play and then again you add in the liquid, so we're in a great position. We don't have to chase things to get our growth and at low costs. I think we have a lot of multi-year baked in low cost growth of which we're ramping up rapidly -- approaching 50 rigs in order to capture that NPV, so that's comment one.

Comment two would be a lot of people are and we have been talking about this and we have a scout team out there looking at different plays. A lot of people are talking about getting into oil shales now and I'm talking pure oil shales -- not at the Bakkan. Bakkan doesn't count because you've got conventional reservoirs mixed in it. The industry now is shifted to we're going to not only look at dry gas shales which were a breakthrough a few years back to the wet gas areas which are hot now -- and again, we're thinking of some of the shales there is no wet gas in some of these shale plays out there. They're in Fayetteville, Haynesville, they're basically dry gas plays. So you can't chase it every where. You have to be in a shale that has that and you have to be in a shale that not only has it, but high quality rock in the right part of it which the Marcellus does.

The companies now are just in the last two or three months are going one more step. Now they're saying we're going to look at pure oil shales and then a lot of people have rushed into that -- oil prices are high, gas prices are low, here is the great new nirvana. That may work or it may not work, but it clearly has significantly higher risk and as an engineer when you're starting to move gas molecules molecules through [nanodarcy] rock and it's not just can you get through the port route, like the big breakthrough is you can move an oil molecule through an nanodarcy port route. In the longrun what matters is comes back to flow equations. What's the shape of that curve going to be over a year or two or five or ten years and how much do you have to pay up front for it. The industry hasn't shown yet that in a big way that they can make that economic. It may work, it may not work.

At Range we have a lot of low risk baked in things we think we can drive that up for years to come. We'll be opportunistic. We'll look at plays, but we're not going to jump at the latest fad I think like a lot of other companies have done which may or may not work. I am just saying from a technical perspective in my opinion it is -- you have changed the risk profile when you have gone from gas to oil because of viscosity of oils at least -- an order of magnitude higher than gas which is going to make it a lot harder long-term to flow through that low quality rock. That was my technical soap box. Onto John for the more global thoughts.

Good question. Something that we obviously talk about a lot as well here internally I think just to reiterate what Jeff said, I think if you sit back and look today, if we had any 8,000-foot oil wells that would come on at 4,000-barrels a day, I can assure we'd be rushing over and drilling those, given the relative prices. But most of those -- there are very few of those that exist today -- and people are trying to buy them more but there really are very few of those fields. As we all know, most of the oil in the US was produced by Rockefeller and his friends back -- a long long time ago.

If you think about this simplistically, if I were out in the acquisition market today and going to buy reserves, what would I buy? I've got to tell you, I would buy gas, not oil. Because I think oil is trading at the high-end and gas, you're getting trading at the low end. Again, I think some of why Exxon bought XTO -- they thought they were buying a resource base that was at the lower end of its long-term view of gas -- I mean prices -- and the NYMEX curve, and I am not talking about this year, but if you look at the NYMEX curve for 10 or 20 years -- it would suggest that. If I am buying reserves 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 economics, figure out which one is going to generate the highest return over the period of time and do that. And I have seen companies -- our friends in Newfield -- shifted some of their capital dollars over to an existing oil field they own and are speeding up that development. I think that is very prudent, and I think Newfield is a great company, and I think it makes absolute sense.

I think what Jeff said is absolutely right, though, to jump out of lower risk projects and put your money into dramatically higher risk projects chasing oil can be a two edged sword. If you're good at that and it works, you're going to over perform. If you don't, then you're going to way under perform. So therein lies the issue is the risk associated with that strategy. I love the strategy because what I am hopeful for is all of these guys do jump into the oil that the natural gas rig count continues to move down. We had some sanity come back in the market last week and saw natural gas rigs decline. Hallelujah. So, I am hopeful as that trend continues more people jump into oil and shift things that natural gas supply will come down, and that we'll see gas prices move back up with a combination of stronger economic growth, more electric generation in the US being developed with natural gas versus the nasty stuff we use today. And the reduction in the natural gas rig count and you will see prices move back up. Maybe not as long as some but I have been in this business a long time and I keep on saying the cure for low prices is low prices.

I think the industry will readjust to these gas prices, and especially I think one point that's important is if you look at the hedges the industry has in place today for 2010, the gas hedges, I haven't seen the number -- we haven't done analysis specific -- but I have read some analysis by analysts where about 70%, maybe even 75% of our hedges for 2010 are actually for the first half of the year, so as those hedges roll off here, in about two months, you will see -- then you will see the rig count even fall down more aggressively. That would make sense to me. Again, one of the reasons why we hedged -- jumped up from 23% to 51% for 2011-- is I am a little concerned with the available access of capital out there -- the ready access to capital -- for just about anybody that wants it in our business I was a little concerned that there may be that market may stay open longer than I think it should, and that some companies would jump out there and grab some capital and continue to drill in an environment they wouldn't normally if they didn't have that ready access to capital, so I think that gives you our summary in terms of how we view all of that.

Doesn't mean we're right. Our view of it is, like Jeff said we found a giant gas field. It has good economics even at 450 gas, so we think we have substantially derisked it, so we don't have a great desire to have to jump out and do something else. We're making good returns for shareholders now as it is and we think we'll continue to do that even if gas stays in the $5 to $6 range for a long time. We feel good about it. I think you will see us not do anything that's high risk if I should put it that way, whether it is an acquisition or new play idea.

Let me add on one other technical comment. Long answer to your question, but I think it is an important question is -- I just wanted to caution people on IP's, a lot of people talk about IP's, jumping the oil shales. I 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 a couple of high rate wells. And as you come up in the Eagle Ford from the dry gas window to the wet gas to the oil, you go basically from a true shale to a basically a carbonate, and it is a black looking rock, but when you look at the mineralology, it is really a carbonate. And when you come up into that the shall part -- in fact, there you have the Eagle Ford, [Buddha], and then Austin Chalk right on top of it in a fairly narrow package. When you look at those early wells, and time will tell -- clearly you can get high rates if you get into a fractured area analogous to the chalk, in fact. Like I said, when you move the Eagle Ford up into some of the shallow areas, basically it is a carbonate which is like -- the same as what a chalk is. Same family.

So there is no question if you get into the good fractured area you can get good initial rates. The question is long-term once you drain the fracture system what's the matrix going to feed into the fractures at. That's really going to tell the tale on what's the rate of return and economics of your well, so again those things may work. They may not work. I am saying it is a different risk profile and the good news is given the inventory we have and the economics of our projects, even down to extremely low gas prices, we can just stay focused on driving Marcellus up and keeping our costs down and improving our wells even at $2.50 gas and $60 oil our Marcellus wells and wet gas area in southwest PA still generate a rate of return of about 35%, so that's what we'll stay focused on.

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 answer session. I would like to turn the call back over to Mr. Pinkerton for his concluding remarks.

We have run way over. Why don't we just conclude today. Thank you all very much for joining us, and we look forward to hopefully similar if not better results in the second quarter. Thank you very much.

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