山脈資源 (RRC) 2009 Q3 法說會逐字稿

Welcome to the Range Resources third quarter earnings conference call. This call is being recorded. (Operator Instructions). Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risk and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers remarks, there will be a question and answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good afternoon and welcome. Range reported results for the third quarter of 2009, with record production, beating the consensus number and clearly continuing to execute our business plan for 2009. The third quarter marked our 27th consecutive quarter of sequential production growth. Range is within our focus now of being able to achieve seven years of quarterly sequential production growth. Although we are encouraged with this ability to grow production, we are more focused on achieving those targets at an optimum cost structure on a per share basis to maximize shareholder values. And I think you'll hear those same principals reiterated from each of our speakers today.

On the call with me are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; and Roger Manny, our Executive Vice President and Chief Financial Officer. Before turning the call over to John, I'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It is now available on the homepage 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, EBITDAX, cash margins and the reconciliation of our non-GAAP earnings to reported earnings that are discussed on the call. Tables are also posted on the Website that will give you detailed information of our current hedge position by quarter. Also, posted on the homepage of our Website is a short video showing one of our walking rigs in Pennsylvania in operation. You might find it interesting if you've not been able to visit our operations in Pennsylvania in person.

Second, we will be participating in several conferences and road shows in the upcoming weeks. Check our Website for a complete listing for the next several months. Jeff Ventura just spoke at the Oil and Gas Investors DUG Conference in Pittsburgh earlier this week. His presentation is posted on the Website. It includes several new technical slides covering our Marcellus development, if you missed it. We will be at Pritchard's Appalachian Conference in Boston on November 16; the Bank of America - Merrill Lynch Energy Conference in New York on November 17; the Friedman Billings Energy Conference, December 2, in New York; and the Wells Fargo Conference in New York on December 8; and Capital One Southcoast Conference in New Orleans on December 9. Now, let me turn the call over to John.

Thank you, Rodney. Before Roger reviews our second quarter financial results, I'll spend a little bit of time reviewing some of the accomplishments for the quarter. On a year-over-year basis, third quarter production rose 13%, beating the high end of guidance. The 13% increase includes the impact of the sale of the Fuhrman Mascho field, effective June 30, 2009. If we hadn't sold Fuhrman Mascho, production would have been a 17% increase. This marks the 27 consecutive quarter of sequential production growth. The driver for this was the higher than anticipated production from exceptional drilling in the Barnett and Marcellus Shale plays.

Second, our drilling program was on schedule throughout the quarter as we drilled 128 wells. We continue to be extremely pleased with the drilling results and despite the lower prices, are generating attractive rates of return. We currently have 15 rigs running versus 23 this time last year. The 13% increase in production was more than offset by a 30% decrease in realized prices. As a result, third quarter '09 financial results were lower than the prior year. We are most pleased on the cost side, as our cash costs were well below the prior year. I'm particularly pleased with the unit lease operating costs, as they were averaged $0.75 per Mcf. This was a whopping 25% lower than last year.

With regards to our Marcellus Shale play, significant headway was made as we continue to drill some terrific wells, building high grade or acreage position, buildout infrastructure and bring down our well costs. In addition we continued to add high quality personnel to our Marcellus team, which Jeff will talk about.

In summary, our third quarter results were the best in our Company's history, from an operating perspective. In particular, we did this while, at the same time, keeping our capital expenditures within cash flow. All in all, I couldn't be more pleased on how much we've accomplished so far this year. It's a real testimony to the entire Range team. With that, I'll turn the call over to Roger to review our financial results.

Thank you, John. The third quarter of 2009 is, in many ways, a reprint of the second quarter of 2009, except for our Herculean effort on production. The oil and gas production set a new record high, despite significant asset sales. And direct operating costs were down even more significantly than last quarter. Importantly, like the second quarter, our liquidity and balance sheet remained just as strong at the end of the quarter as the beginning.

Oil and gas sales for the third quarter, including cash settled derivatives, totaled $255 million, down 21% from the $322 million in revenues last year. And as John mentioned, the 13% increase in production just could not offset the 30% decrease in oil and gas prices. Sales and production were both higher than in the second quarter this year, which as John also mentioned, is a noteworthy achievement given our June 30 sale of the Fuhrman assets, which were producing approximately 15 million a day. Cash flow for the third quarter of '09 was $171 million, 25% below the third quarter of '08 but up $15 million from the second quarter of this year. Cash flow per share for the quarter totaled $1.08, $0.04 per share higher than the analysts consensus estimate of $1.04.

Quarterly EBITDAX of $198 million was 22% lower than the $254 million earned in the third quarter of '08. And cash margins for the third quarter were $4.14 per Mcfe. That's higher than the $3.93 per Mcfe last quarter but 35% below last year due to lower oil and gas prices. So the real story on margins for the quarter is the 15% reduction in cash expenses. We shaved $0.40 per Mcfe in cash costs off of last year's third quarter figures, with lease operating expense down 25% year-over-year. Like last quarter, mark-to-market hedge accounting pushed us into a pre-tax loss position. Albeit a pre-tax book loss of $45 million for the quarter, rather than last quarter's loss of $62 million. The non-cash derivative mark-to-market loss for the third quarter totaled $53 million.

It's counterintuitive the way these mark-to-market gains and losses always seem to go the opposite direction of prices. And perhaps the easiest way to explain it is that when prices were falling last year, we were booking large non-cash mark-to-market gains, as our hedges became more valuable. Now that prices are firming again, we are having to book losses, as our hedges are comparatively less valuable than when prices were lower in the previous quarter.

Going all the way to the bottom line for a minute, before drilling down on third quarter costs. Quarterly earnings, calculated using analysts consensus methodology for the third quarter, were $41 million or $0.26 per fully diluted share. That's $0.04 higher than the analysts consensus estimate of $0.22. The quarterly GAAP after-tax net loss was $30 million. As Rodney and I never fail to mention, the Range Resources Website contains a full reconciliation of the non-GAAP measures mentioned on this call, including analysts earnings, cash flow, EBITDAX and cash margins.

As I mentioned earlier, the third quarter of this year represents the first full quarter following our second quarter Fuhrman asset sales. Not only were we able to make up the lost production volume from the sale, we were able to replace the production from substantially lower operating cost areas. The asset sale, combined with continued downward pressure in service costs, is what lead to the third quarter of direct operating expense figure of $0.75 per Mcfe. The good news on the cash -- or on the costs gets even better when you add cash production taxes to the total. Now, because production taxes are based on wellhead prices, not hedge prices, production taxes for the third quarter were $0.19 per Mcfe, compared to $0.43 in the third quarter of last year. And we're optimistic that these recent operating cost reductions will hold and that cash direct operating expense in the mid $0.70 per Mcfe range may be expected in the fourth quarter.

General and administrative expense, adjusted for non-cash stock compensation, was $0.57 per Mcfe, that's up $0.03 from the third quarter of last year. The primary reasons for the G&A unit cost increase are the closing of our Houston office and the resulting $840,000 accrual for severance and an increase in our reserve for bad debts of $1.1 million. These items totalled $0.05 per Mcfe, which accounts for the G&A unit cost increase from the second quarter. We will record additional expenses associated with the closure of the Houston office in the fourth quarter as they're realized but the office closure will reduce future G&A expense by approximately $4 million. This will be redeployed into our high growth areas, primarily the Marcellus Shale.

The non-cash deferred compensation plan expense was somewhat higher this quarter at $16.4 million. Long-time listeners will recall that this non-cash mark-to-market expense was primarily a reflection of the increase in the value of Range common stock held in the deferred comp plan. It does not represent a contribution to the plan or the change in anyone's compensation. We expect recurring cash G&A expense per Mcfe to hover around the $0.55 mark for the fourth quarter.

Interest expense for the third quarter of '09 was $0.76 per Mcfe. That's up $0.05 for the third quarter of last year, as we replaced short-term floating rate bank debt with additional long term fixed rate subordinated notes earlier this year. Total debt outstanding has been roughly constant all year long. Exploration expense for the third quarter of '09, excluding non-cash stock comp expense was $10 million. Now, this expense was $8 million below last year, with the reduction mostly coming from lower seismic expense. We expect total fourth quarter exploration expense to be in the $12 million to $14 million range.

Depletion, depreciation and amortization per Mcfe for the second quarter of '09 was $2.42. That's up $0.17 from the prior quarter and $0.27 from the prior year. This higher figure stems from three factors. One, the mature Fuhrman assets we sold had a depletion rate 20% below the Company average. Two, incremental production offsetting this sale came from areas such as the Barnett and Marcellus, where the depletion rates were still above the Company average. Reflecting many years of early stage exploration and development expenses, without corresponding reserve additions. Three, we have reallocated capital from our mature legacy fields with low depletion rates to higher rate of term projects. And that has reduced incremental production from the mature lower depletion rate areas.

Now, this type of increase in DD&A should be temporary. As next quarter, we will be resetting our DD&A rate based upon our year-end reserve report, which we'll include the results from our highly successful 2009 drilling performance. While completion of the year-end reserve report is still several months away, our experience in the Barnett Shale has taught us to expect declines in the depletion rate over time, as early stage shale play R&D costs are amortized and capital efficiency improves. It's also worth remembering that Range has experienced no meaningful property impairments, so our DD&A rate has not been reduced the wrong way. That is, by multibillion dollar ceiling test writedowns.

One of the primary drivers of our improving capital efficiency at Range is our practice of allocating capital on a realtime basis. Well economics are not only run each year during the capital budget process but before each well is drilled. Now, this enables us to shift our drilling capital to the areas where we are seeing our best returns and requires all Range divisions to continually improve their returns to be competitive. We are witnessing the fruits of this labor as we are producing solid double digit production growth this year without acquisitions and despite asset sales, with fewer than 50% the number of rigs as last year.

There is a bit of a downside associated with this practice, however, when it comes to accounting for unproved property. The decision to drop rigs and reallocate drilling capital means that we will not be drilling on certain leases to have near term expirations. This prompts us to continually reexamine the status of our leasehold position and take additional impairments to our unproved properties in areas where we deem the acreage less valuable or likely to expire. What this means for the third quarter of '09 is that we impaired $24 million in unproved properties versus $5 million in the third quarter of '08. Eventually, we expect the level of these impairments will normalize as unproved property works its way through the acreage life cycle and our drilling activity increases.

Investors wishing a more extensive explanation of the unproved property impairment process, for successful efforts of accounting companies and how it compares to full cost companies, may wish to review my conference call comments from the first and second quarters of this year. Now, the Cliff Notes version of those comments is that an investor should treat unproved property impairments for successful efforts companies in the same way they treat ceiling test impairments for full cost companies. And we anticipate unproved property impairment of between $16 million and $18 million in the fourth quarter of this year.

Range recorded a $15 million deferred tax benefit for the third quarter and we booked a $695,000 income tax benefit for the quarter. And with our filing of the '08 Federal return, our NOL carry-forward at the end of the year is $291 million. Approximately $140 million of this carry-forward will be used to offset the taxable gain on the sale of the Fuhrman assets. The NOL used will be replenished in $09 through intangible drilling cost reductions. We anticipate a 36% tax rate for all of 2009. Range continues to benefit from its 2009 hedges and we have approximately 2/3 of our fourth quarter gas production hedged at a floor price of $7.79 an MMBtu and a ceiling price of $8.53.

We've also continued layering in additional hedges on our 2010 production during the third quarter. Price collars are now in place covering approximately 50% of our expected natural gas production for all of 2010. Slightly more than 50% of the first half of 2010 production is hedged with a floor price of $5.50 an MMBtu and a ceiling price of $7.45. We have slightly more than 40% of our second half 2010 production hedged and those are the collars at $5.59 by $7.50 for an MMBtu.

The best news on the balance sheet front this quarter is that there is no news. Overall debt-to-capitalization is essentially flat, 43%. And bank debt is actually slightly down this quarter at $398 million, compared to $403 million last quarter. The absence of incremental debt and equity reflects our disciplined approach to capital spending, holding spending to within cash flow and asset sale proceeds. And we announced earlier this month that the 26 member Range bank group has unanimously reaffirmed, unchanged, the $1.5 billion borrowing base under our credit facility. And our current bank debt balance provides Range over $1 billion in unused borrowing base capacity and approximately $850 million in committed liquidity.

While I jest about no news being good news on the Range balance sheet, there are actually some very important stories going on behind the numbers here. Now, there's a story between the lines regarding our bank borrowing base redetermination. Range completed a significant asset sale last quarter and we are in a significantly lower gas price environment. Yet our bank borrowing base was reaffirmed at the same $1.5 billion level, in a still challenging bank credit market, without any changes to the interest rate or terms. The story here is about our creditworthiness. Specifically, the quality and diversification of our asset base, our low cost structure and our ability to consistently and efficiently replace not only reserves produced but even assets sold.

There's another story told by the fact that our balance sheet leverage in '09 has not increased, even though we are cranking out double digit production growth, unaided by prior year proven property acquisitions. This story is one of spending years building a class-leading drilling inventory, with rigorous capital spending discipline and prudent asset sales. Or stated simply, high grading our investment opportunities and living within our means during a tough commodity price cycle. There's also a story further down the balance sheet, as we have not made a cash secondary offering on the equity side since 2008. This story is one of focus upon true value creation for you, our shareholders. Low cost, consistent reserve and production growth, not on an absolute basis but on a per share basis.

Some quarters stand out for what happened and some stand out for what did not happen. And the third quarter of '09 brought a bit of both for Range. Solid incremental improvements in production volume, cost reduction, cash flow and our hedging position. All the while, respecting the balance sheet. So, John, I'll turn it all back to you.

Thanks, Roger. Now, let's hear from Jeff on the operations.

Thanks, John. I'll begin by reviewing production. For the third quarter, production averaged 437 million per day, 13% increase over the third quarter of 2008 and this represents the highest quarterly production rate in the Company's history and the 27th consecutive quarter of sequential production growth. This is a great accomplishment by the team, given that we closed on the sale of Fuhrman right at the end of the second quarter, which reduced production by about 15 million per day. Also, we dropped rigs in the southwest and mid-continent divisions throughout the second and third quarters. To overcome all of that is outstanding.

I'll begin with the operations update with the Marcellus Shale. To date, Range has drilled and completed 60 horizontal Marcellus Shale wells. 54 of the wells are currently online and today, we're producing over 80 million per day net. Our current cost to drill and complete one of these wells in the Southwest Pennsylvania, from a multi-well pad, is about $3.5 million. Based on the zero time plot we released earlier, which includes 24 wells. our expected ultimate gross recovery is 4.4 Bcfe. Factoring in the production profile, which is shown on our Website, our average royalty and current gas price adjustments and assuming a $5 per MMBtu gas price, results in a 46% rate of return and a cost to find and develop of $0.95 per Mcfe. At $7 gas price, the rate of return increases to 75%.

We believe this is the best rate of return in finding and development costs of any large scale repeatable play in the United States. In the past, I've stated that the average reserve expectation across all of our acreage position is in the 3 Bcfe to 4 Bcfe range. To date, our average well has been about 4.4 Bcfe, which is above the top end of the range. I urge caution that more wells and more production are necessary to determine what the actual number will be. We're still very early in the development of this play. For now, I'm still comfortable with the 3 Bcfe to 4 Bcfe range for the expanse of our acreage and where it is located.

In the southwestern part of the play, we have approximately 550,000 net acres. To date, we've drilled and completed 117 wells in the area. 60 of these are horizontal wells and almost all were successful, excluding the initial science wells. The distance between our northern and southern most horizontal Marcellus Shale wells in southwest Pennsylvania is 40 miles. The distance between our eastern and western most horizontal Marcellus Shale wells in southwest Pennsylvania is 41 miles. Within this box, we have 177,000 net acres or 32% of our 550,000 net acres in this part of the play. Based on our early results we feel very strong about this area. We consider it low risk and have moved into the commercial development of this area.

In the same area, the distance between the industry's northern and southern most wells is 81 miles. The industry's eastern and western most wells in southwest Pennsylvania is 59 miles. Within this box, Range has 390,000 net acres or 71% of our 550,000 net acres in southwest PA. Approximately 320 industry wells, including Range's wells, have been drilled in and around Range's acreage, which has significantly derisked even more of Range's acreage. Using just the 390,000 net acres, within what we believe are the low risk, high chance of success derisked box, and assuming that 80% of the acreage is ultimately drilled, and assuming 80-acre spacing; we can potentially drill 3,900 horizontal wells. Assuming 3.5 Bcfe per well, that's 13.7 Tcf gross or 11.6 Tcfe net unrisked reserve potential for Range.

On our acreage in the Southwest, gas in place averages about 100 Bcf per section. Assuming 80-acres per well and assuming that the wells average 3.5 Bcfe recovery, the recovery factor calculates to be about 24% of the gas in place. It's possible that through a combination of improved recoveries per well and tighter spacing, we may be able to significantly increase the recovery of the gas in place, which is what historically the industry has done. Range is currently a 2.7 Tcf Company. Therefore, we have the potential to grow significantly from just this one play, in just this one area. Importantly, the expected rate of return on this capital is exceptional.

In the northeast portion of the play, we have an additional 350,000 net acres. This represents another 5 Tcfe to 7 Tcfe of net unrisked reserve potential for Range. We're currently drilling two back-to-back horizontal wells in the northeast. Both horizontal wells offer excellent vertical wells or offset excellent vertical wells that we previously drilled and tested. We also see significant upside potential in both the Utica Shale and Upper Devonian Shales on our portions of our acreage. Prior to year-end, we plan to spud two horizontal wells to touch each of these concepts.

At year-end 2007, Range's Marcellus production was about 8 million per day net. At year-end 2008, we were producing about 26 million per day net. At year-end 2009, we should be about 90 million to 100 million per day. And we're currently planning on doubling that to 180 million to 200 million per day by year-end 2010. Future growth beyond that looks encouraging. We're currently running five big rigs and four smaller air rigs drilling ahead of them. We'll have one additional horizontal rig drilling by year-end.

I want to discuss one last item for the Marcellus project. We've made very significant progress in regards to water. We're currently recycling 100% of all of our water in the development area in the Southwest. When we frac the horizontal well, we only get roughly 15% to 35% of the frac water back. The rest stays in the formation. Now, that we're pad drilling in the southwest, we have water retention facilities that service multiple wells. We start with 100% of the required water, pump it into the well being stimulated and then flow the water back. As mentioned previously, the well flows back only a fraction of the water back into the water containment. And then, it's refilled back up in order to frac the next well. And so, on for future wells.

This is really important because it significantly reduces the amount of water required for fracturing and also eliminates the need to truck the flowback water away and dispose of it. This zero discharge method of doing business results in great cost reductions from not having to truck and dispose of water. From both an environmental and economic point of view, it's clearly the way forward.

I'm very proud of our team for pioneering the Marcellus play in Pennsylvania. Our team now consists of approximately 190 people. Approximately 40 of these people are either engineers, geologists, geophysicists or landmen. I believe that we have one of the best shale teams in the industry. We continually look at adding first round draft picks to the team when possible. Recently, we've added two outstanding individuals to the team.

Joe Frantz, who has a Petroleum and Natural Gas Engineering Degree from Penn State and about 26 years of industry experience, recently joined our team. He's a recognized leader in developing unconventional gas and has worked on all of the major shale plays in the US. Joe actually did some of the engineering work on our first shale well in the Marcellus, which was a success. At the time, he ran Schlumberger's Appalachian office in Pittsburgh. The other person who recently joined out team is Scott Roy. Scott has 17 years in public service in various positions, including key roles in both the Ridge and Rendell administrations and acting as the Governor's liaison to various regulatory and environmental agencies . Scott will play a key role in forging strong partnerships among public, regulatory and industry interests to ensure that development of the Marcellus Shale is accomplished in a responsible way.

Let me briefly update you on our two other major properties. Staying in the Appalachian Basin, I'll discuss Nora first. Successful drilling continues in all three horizons. In the coalbed methane, we had a very good year, most of the in-fill wells are performing on par with the original wells. And in some cases, drilling the in-fill is improving the original well on the spacing unit. CBM wells today are costing about $340,000 and the reserves are about 350 million. At a $5 flat gas price, the rate of return is about 32%. At $7, it's about 58%. The vertical-type gas sand wells have even higher rates of return. At a $5 flat gas price, they generate a 40% rate of return and this improves to 73% at $7.

We're currently experimenting with horizontal drilling in the Berea Sand and Big Lime formations, with encouraging results so far. We've also now drilled about 20 horizontal Huron Shale wells, so far, scattered across our acreage position. This looks very good and has derisked approximately 1.5 Tcf to Range from this horizon alone.

In the Barnett, although we've decreased our rig count from about six rigs at the beginning of the year, to one currently, we've driven production up from 1,10 million at the beginning of the year to about 1,30 million per day today. This is an excellent job by our Barnett team. The rates of return on our Barnett wells are still very good. Even at $5 gas, they're still 32%. We have many locations to drill in the Barnett but fortunately, we don't have any significant drilling commitments. The bulk of our acreage in the core, where our remaining locations exist, is largely held by production. So, as good as Range has been in the past, we should be even better in the future.

The F&D costs for all major three properties, the Marcellus and the Barnett Shales and Nora, ranges from about $1 to $1.50. And the LOE's from all three properties are low. It's also important that two of our top three projects are in the Appalachian Basin, where the gas price has been better than anywhere else in the US. Range has consistently delivered top tier organic production and reserve growth, with one of the lowest cost structures in the business. This is the direct result of our simple strategy of strong organic growth, at top quartile cost structure or better. And, in addition, consistently building and high grading our inventory. Coupled with one of the best teams in the industry.

We believe Range today has more upside and lower risk upside than at any time in the Company's history. With our inventory, we have the opportunity to grow the Company more than 10-fold, primarily from the Marcellus Shale, Nora and the Barnett Shale. We believe our excellent organic growth, combined with an excellent cost structure, will result in continuing to create strong shareholder returns over time. Back to you,

Thanks, Jeff. Terrific report. Looking to the fourth quarter of 2009, we see continued strong operating results. For the fourth quarter, we're looking for production to average 455 million to 460 million per day. Representing roughly a 14% increase year-over-year and approximately a 5% increase over the third quarter of '09. Taking into account both the asset sales and the drilling results to date, we have increased our full year 2009 production growth target from 10% to 13%. Given our reduced capital program, we are focused on -- we've focused about roughly 90% of our CapEx on the Marcellus, Nora and Barnett plays. These plays generate attractive returns, even at low prices. As Jeff discussed, we're fortunate that the remaining properties we have, have a shallow decline curve. In particular, our tight gas sand properties in Appalachia and West Texas, on a decline of roughly 10%.

Now, one of the key elements that we have talked about from time to time, that's having a very key impact on us, is our capital efficiency. As Jeff mentioned, in the last several years, we've spent considerable capital in the Marcellus play without getting or seeing much of return on that. Beginning in October of '08, 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, we are seeing this capital efficiency impact having an ever increasing impact on our Company. This is allowing us to do more with less.

In the third quarter, our CapEx totaled $171 million, including the $4 million of Marcellus acreage we acquired in exchange for Range common stock. So, our cash CapEx total was $167 million, which was fully funded by $171 million of operating cash flow. For the full year of 2009, our cash flow and completed asset sales should be more than adequate to fund our CapEx program. After closing the Fuhrman Mascho sale, our Board approved that 6% increase in our 2009 CapEx budget from $700 million to $740 million. The additional funds were used to acquire acreage in areas where we've had our drilling success and primarily, in the Marcellus play.

At year-end 2008, we spoke about the transformation that would take place once we began to ramp up our Marcellus production. The third quarter results clearly reflected this transformation. In the third quarter, we were able to significantly increase production and decrease costs, maintain capital spending within our cash flow. Thereby, strengthening our financial position. This was done without the benefit of producing property acquisitions or having to go to the market and issue equity to fund our growth. In my opinion, it is this kind of performance that drives shareholder value in our business.

Next, I'll spend a few minutes discussing the Marcellus Shale play. As mentioned in our release and as Jeff has discussed, our Marcellus production, net to Range, is running over 80 million per day. Assuming no major pipeline issues, we anticipate reaching the high end of our 90 million to 100 million range by year-end. In addition, we have significantly reduced our drilling costs in southwest PA to roughly $3.5 million per well, as Jeff mentioned. In addition reducing costs, we're finding ways to do things in a more proactive environmental manner by recycling 100% of the flowback water in southwest PA.

Looking ahead, there are some very exciting next steps that are taking place in the Marcellus. First, the pipeline and infrastructure buildout is going very well. Within the next 90 days, the start up of the 120 million a day gas processing plant should take place. Second, we have commenced drilling our first two horizontal wells in northeast PA, that offset two of our best vertical wells. We have a very large acreage position in the northeast PA, covering roughly 350,000-acres. Third, we spudded our first Utica horizontal well. And fourth, we should spud, shortly, our first Devonian Shale horizontal test. Now, these four wells are important because if they are successful, it could add multiple Tcf of additional reserve potential to Range. We should have some of the preliminary results on these wells by our year-end conference call when we report year-end results. So, that's pretty exciting.

Lastly, I'll spend a few minutes discussing the outlook for 2010. We're working on the 2010 capital budget and there are several avenues we can take. Currently, we expect to take the same type of approach we did for 2009. We expect cash flow and asset sales to fund our 2010 capital program. We've recently identified the properties we anticipate selling. Taken a rough cut at the asset sales, combined with the expected cash flow, we believe we'll be able to execute a capital program that will once again deliver solid double digit production growth at low cost. Specifically, when you look at 2010, the Marcellus will be our primary growth driver. We plan to double the Marcellus production in 2010. Therefore, we are looking for a net production in the Marcellus to reach 180 million to 200 million a day by year-end 2010.

I think the keyword here is 'net production'. As many producers provide gross volumes, which in my opinion, are not relevant. This is especially true with all of the joint ventures that are being done where companies are selling off percentages of their entire acreage position. We continue to believe that we want to maintain our entire position in the Marcellus and grow it versus selling part of it off to a third party. Also, joint ventures are never easy to manage, so we prefer not to complicate our operations with joint ventures. Said another way, we'd prefer to sell our higher cost, more mature properties and maintain and grow our higher return, higher potential properties.

On the equity issuance question, our strategy remains unchanged. We prefer to sell properties versus selling equity. Given that we expect cash flow and asset sales to once again fund our capital program, we don't currently see any need for selling equity in 2010, unless we have an opportunity to make an attractive acquisition of a sizeable acreage block or producing property package in one of our key project areas. In looking at Range today, we have the largest and highest quality drilling inventory in our history. Our inventory, together with our emerging plays, represents 20 Tcf to 28 Tcf of future growth potential. This equates to seven to 10 times our existing proved reserves.

While we're excited about the potential growth at Range, we're intently focused on delivering each quarter. I think the third quarter of '09 is a shining example of this committment by all of the employees at Range. And I compliment each one of them for their excellent work in the quarter. With that, operator, let's turn the call open for questions.

Thank you, Mr. Pinkerton. (Operator Instructions). Our first question comes from Mr. Tom Gardner with Simmons & Company. Please proceed with your question.

Thank you, operator. John, just circling back on what you just said with regard to the rigs moving into the northeast portion of the Marcellus. I believe Jeff mentioned on the last call that those rigs were moving in there in August. Just wanted to see if you had any sort of results to date and perhaps get an update on the development timing in that northeast portion of the play?

This is Jeff. Let me take a crack at that. Tom, I did say that on the last call. The rigs we're getting are the special built rigs and they were slow to be delivered. So, that got delayed a little bit. But we're currently drilling simultaneously two wells in the northeast. One offsets our best vertical well. We made over 6 million per day from a vertical well. So, we have high hopes for that. And the other one is offsetting, also, an excellent vertical well that made over 2 million per day. They're drilling simultaneously. They're already at significant depths. So I feel comfortable we'll have results by the end of the year.

We're already pre-planning. Once we drilled the good vertical wells, we shot 3D to cover it. So we're drilling the horizontal wells off the 3D, directly offsetting the vertical. We've already acquired pipeline right away. We've already acquired our caps. So I think that area, I have good hopes for, high hopes for. And I expect it will come online towards the end of next year. With good results of these two wells, you'll see us doing some drilling in the northeast next year. Primarily, focused in the southwest, ramping up production, continuing to drill in the northeast. And then, we'll have our pipeline on there by the end of next year. It's all going to be dry gas. With significant development in 2010 in that area.

Thanks, Jeff. Just staying with the northeast portion of the play. How much acreage do you currently have in New York and can you give us an update on these regulatory initiatives and the ultimate impact perhaps on drilling in the state?

Well, we have roughly 2 million-acres in the Basin. When we talk about 1.4 million-acres for the Marcellus, as prospective, let me talk about that. That 1.4 million-acres, basically, is almost all in Pennsylvania, a little bit in the West Virginia panhandle right adjacent to Pennsylvania. We're not counting any New York acreage at all as being prospective for the Marcellus. And when we talked about our hydrated acreage, the 900,000, that's basically again almost all in Pennsylvania, a little bit in the West Virginia panhandle. And the difference, that other 500,000-acres has potential for the Marcellus but it's behind pipe in existing wells that we have. There we'll be looking at it as a recompletion potential or later on but it's on HBP Oil and HBP acreage.

So, when we originally went back and targeted the Marcellus, when we started to play several years back, we targeted different areas predominantly in the southwest Pennsylvania and northeast Pennsylvania. We did not target New York. I'm not saying New York doesn't have potential. It just wasn't within our originally targeted areas. And as we've continued to refine our model, our model actually has held up very well and has been very robust. And we continue to target basically those same areas.

Yes, Tom and this is John. I think Jeff's perspective is more, let's say, from a geological perspective. The other perspective is kind of the business perspective. And as you know and maybe some people don't, we've been operating up in Appalachia for over 25 years now. And we are one of the largest producers of natural gas in the State of New York. That doesn't mean a lot but we're still one of the largest producers in New York. So, we know firsthand how difficult, on a relative basis, is New York versus PA versus West Virginia versus Ohio versus Virginia. And we take all of that into account when we looked at this play. And there is no doubt in our minds that New York was going to be more challenging from a regulatory perspective. It always has been and in my view, always will. And I don't want to go into why we believe that but I think most people can just see that for themselves. I'm not bringing up something that I think is all that earth shattering here.

So again, I think there's, in all these plays, whether it's the Barnett or whether you want to be drilling wells in downtown Fort Worth or whether it's the Marcellus or all of the other plays, you've got to take your technical work and overlay it with what you think the business risks are. And quite frankly, when we did that, New York was not one of the ones that popped out where ought to be buying acreage. So that, in a nutshell, is why we don't own any material Marcellus potential in New York. Again, just want to reiterate what Jeff said, is that it's not that we don't there's -- think that it's bad. We just think Pennsylvania is better.

Got you. Thank you, guys. I'll let someone else hop on. I always have more questions, though but I'll let someone else take a crack at it.

Thank you. Our next question comes from the line of Ron Mills with Johnson and Rice. Please proceed with your question.

Good morning. Just to follow-up on the northeast PA and somewhat of what you were just speaking of, John. From a permitting standpoint, any -- can you walk through some of the differences in terms of the northeast Pennsylvania permitting process and time frame versus what you're experiencing currently in the southwestern portion of the state?

Well -- go ahead. John and I are battling on who was going to answer. We can both chime in. I'll go first. When you talk about the southwest, the process has become good, it's significantly improved. I think we routinely get permits in 30 days or in some cases, significantly less. So, that's going well. In the northeast, again, it's easy -- when we talk about areas, these are large areas. You're talking about a state. Whether you're in the Delaware River Basin or Susquehanna River Basin, it makes a difference. Where we are and the farther east you go, the more difficult that gets. And we don't have any acreage out in the far east either, which is -- again, we start with the technical analysis of where we want to be and then, overlay the business aspects to that as well. So, we've been able to get our permits and to move forward. John, do you want to add-on to that?

Yes, again, I think the key here is is that clearly over the next year or two, the major driver is going to be the southwest for us. We're going to drill some wells in the northeast. We're excited about the potential but in terms of delivering the gas in the pipeline and ramping up the production, it's going to come from the southwest. Or the great majority of that is going to come from the southwest. In that area, as Jeff mentioned, the permitting process has gotten very routine, 30 days. I heard, recently, we got one permit in eight days, to give you an example. We've got a program there. We've got a fairly blocky acreage position. So it's going quite well just like it does in the Barnett or the Woodford or any other plays that we're in, in terms of horizontal drilling. So, it's become like clockwork.

The northeast, as you move away -- and again, you've got to think about how the oil and gas in Pennsylvania was first developed. Most of the oil and gas in Pennsylvania was developed in the southwest part of the play. In fact, our [Rens] well, our first well drilled in the Marcellus isn't too far away from the first oil drilled in the United States by Colonel Drake, which was exactly 150 years ago on August 27. Which also happens to be my anniversary date, that's why I remembered. So because of that, you've got all of the infrastructure and all of the other things down in the southwest. The northeast, there's just less infrastructure. There's been less drilling up there, there's less service. So again -- but that will over time, that will solve itself, just like it has in the southwest.

The Southwest now in terms of services and everything else has become pretty much just like the Barnett. So again, that's one of the reasons why we've been able to drive down costs because now you're getting competition for services and things are more routine. So, again, all that relates to how you allocate capital. We can go faster in drilling in the southwest when compared to the northeast just because of those reasons. So again, that's why we're focused in the southwest because we think, from a risk perspective, from reserves, to business, to service, all of the other stuff you have to think about, that's where we're focused.

That being said, again, like Jeff said, that there's enormous -- we've got 350,000-acres. We're one of the largest leaseholders in the northeast. And people forget about that all the time. And so, we're really excited about these two wells, to say the least. And hopefully, knock on wood and do a couple of back flips but come year-end, we'll be able to get you some pretty interesting results from those wells.

Okay. And from the Utica standpoint and/or the Upper Devonian and obviously, you've seen the Upper Devonian in your Marcellus wells. But from an aerial extent or from an acreage standpoint, how much of all your acreage do you think you end up with some Utica potential? Obviously, depending on some test wells being successful.

Yes, we have, we think, a significant portion of our acreage is prospective for the Utica. Particularly, the acreage that's in the southwest. And again, we have 550,000-acres there. We have a big position. Same with the Upper Devonian Shales. We think it's more prospective on the western side. And a lot of our acreage, we think, has potential for that. So, combined, they offer really significant upside. So it will be interesting tests. We'll drill both of them this year, complete them this year. It may go a little into next year. So, by the time we have some results, it should be the first quarter of next year.

Great. I'll let someone else jump in. Thank you, guys.

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

Thank you. Good afternoon, everybody.

Hi, Joe.

Jeff, could you quantify the operating cost savings you get from recycling the water and using the retention facilities? And how much of that savings have you seen already?

Yes, it's very significant because when you have to truck water it's expensive to truck it and then pay for the disposal facility. You're looking at a savings per well, literally, on the order of $200,000 per well. So it's very impactful. So, it's clearly economically the right thing to do but I really want to stress, environmentally, it's really the right thing to do. Because it really reduces the amount of water you need on the front end and then you get the zero discharge. So, when you're in a development area with pad drilling, it's really exciting. And again, I don't want to -- I really want to stop and talk about that point because a year ago most people say that you couldn't do it. Even earlier this year, there were a lot of people very skeptical that it could even be done. And then it moved into; What would it do to the wells? And okay, we can do it but what about the quality of the wells?

Well, not only have we been able to do it but the quality of the wells, we've seen no difference at all. So that's really important. So, I think that when you look at water recycling, coupled with, we're also doing a lot of experimenting with disposal wells now. So, if you can couple those two things together, that's basically taking care of all of the water issues.

Okay, that's helpful. And then, in terms of the operating costs on an Mcfe basis because of this savings, should we see that, all other things being equal, come down fairly decently?

Yes, when you looked at, let me talk about the Marcellus in general, you have two things going on. One, you have high rate flowing gas wells, which are relatively inexpensive to operate. And then, if you can eliminate trucking, you're looking at LOE's for Marcellus really of less than $0.10 per Mcfe. So, as we continue to ramp and build Marcellus and you add that in to the rest of the Company, it's going to continue to drive down our LOE's. Coupled with the fact that part of our strategy is building high grade inventory.

So, we're focusing on our more efficient projects that not only have lower LOE but lower F&D. And then, you're going to couple that with selling things like Fuhrman that have high LOE. And that's part of the reason that you're starting to see really significant impact in driving down LOE. But it's going to -- like I talked about on the last call, when you look at capital efficiency, you're going to see -- even though as good as Range has been, I think you're going to see even better improvements really going forward.

And Jeff, this is -- sorry, Joe. Let me interrupt here. Jeff, let me ask the question then. Then, why the hell did our DD&A rate go up? Let me answer that, Jeff.

Let me chime in after you're done but go ahead.

And let me give some -- Roger, I think, went through the technical accounting and policy mumbo jumbo, if you want to call it that. But let me give you a big picture and kind of from a businessman's perspective. Is that if you think -- one, is we're all in successful efforts. So, we don't do things -- when we calculate DD&A, we do it by property pool. So all of the Marcellus is a pool by itself. We don't just take everything and throw it together, like the full cost guys get to do. So we do pool by pool and we've got a number of pools in the Company. So, I think change within those pools, it changes the DD&A rate. And as you change the production rates between those pools, your overall DD&A rate can change.

And so what happened was, is that we bought Fuhrman -- the good news, Chad and his team were able to buy Fuhrman at a very low price. Our guys did a great job of developing Fuhrman at a low cost. And I think we bought Fuhrman $10 million or $12 million and we sold it for $180 some million. So, that's an A+, check the box for all that. But when we sold it, it still was a relatively low -- even though it had really high operating costs, over $2 an ounce, it had a low DD&A rate. So, you take that out and you replace it and we replaced it with Barnett and to a large degree the Marcellus.

Now, let's talk about that for a bit and let me just zero in on the Marcellus. Is that, if you think about what the Marcellus is, is that, since October of 2004, we've spent a whole bunch of doug, almost $1 million in the Marcellus. And we've spent an enormous amount of money on science and we've spent a lot of money on vertical wells. Which, we still would have done, thinking back at it, maybe done a little bit differently, probably drilled a few less vertical wells. But there's a big science bucket there of costs that we've got to overcome. So at the beginning of the year, you take each of those tools and set your DD&A rate for that pool. Okay? And even though production is going -- so now, production in the Marcellus is actually going up and being a bigger part of the total.

So, its impact is more. What we haven't done - what we don't do is, every quarter, as we drill more wells, change our DD&A rate in the Marcellus. If we had done that, our DD&A rate would not have gone up. But we do do it once a year and we're going to do it in the fourth quarter based on year-end reserves. And once we do that, you'll see the DD&A rate for the Marcellus come down significantly. And like Roger said, it's too early to tell, don't have the numbers. Al and his team are still working on all the reserve numbers and you've got to do all the costs and year end. But you'll see that come back down. So, as Roger mentioned, that was a temporary phenomenon due to the nuances of accounting 101. So, that's the reason for that.

But I really wanted to talk about that because it seemed weird to me that we keep on talking about being low cost and our DD&A rate is going up. And I'm sure most investors saw that, as well and are asking the same question. So again, trying to be transparent and give you a businessman's view of it. And the good news is, I think over time, as we drill and drill in more and more Marcellus wells, you'll see the DD&A rate continue to go down. And that will have a positive impact on the Company. And the DD&A rate and the final development costs will begin to merge.

Good question, John. And Roger, just back to LOE for one second. As a reference point, if you had to truck the water, what do you think your LOE would be?

Yes, just looking, our early disposal costs was dead even at $0.11 this year over last. So, that was not a huge change. I think in answer to your other question, we really haven't seen the P&L benefit of the recycling, yet, flow through for the Marcellus. Since that's relatively new.

Okay and then separate item. In northeast Pennsylvania, when you finish those two horizontal wells, will you place them on to production right away?

No, like I mentioned earlier, just to clarify, the pipeline won't be up and running until the end of 2010. So we'll drill them, we'll test them and we'll then shut them in. And you'll see us do some drilling around them but that will come on as a batch around the end of 2010. And then, 2011 you'll see a significant ramp up up in that area.

Okay, very helpful, thank you.

Thank you. Our next question comes from the line of Monroe Helm with CM Energy Partners. Please proceed with your question.

I think my questions have been answered but just a quick one on the Marcellus. If you had better infrastructure there, could you accelerate the pace of drilling over the next two years? Is that kind of a limiting factor?

What you'll see us do is basically -- it's early, we're building our budget now. We present it to the Board in December for approval and typically talk about it January to February. But roughly speaking, at this point in time, you'll see us double the number of wells next year versus what we drilled this year. And like we said, basically, double our exit rate from next year to this year. We understand, like I said, within that derisked box, we think we have the potential to drill a significant number of wells and develop really over 11.6 Tcfe, just on what we've proven up so far. So, you're going to see significant growth.

But the important part -- and we clearly understand the concept of NPV. That is not new to us. We understand that and that it drives value. We've run a number of scenarios looking at the whole play through depletion. How fast we should drill? How does that relate to our balance sheet and the pipelines and everything else. But I think when you start -- we have a graph on our presentation that shows the trajectory of our growth. And to develop what we think is the multiple Tcf play, there's a lot of upside. And we think, ultimately, when you get to full development, you're going to see a large number of rigs. And potentially, you're going to be probably looking at 50 rigs or so out in the future.

So, we'll be developing. We'll be driving up production. But we're also, remember, our story is not just about growth, it's about growth at low cost. And we think the pace we're going at is a good pace and it's impressive growth but we want to be sensitive to the balance sheet and to funding and all those types of things as well.

Yes, and great question, Monroe. And I think it's -- this year, we really and probably made a large degree and I'll let Jeff take it. But we really wanted to see our -- we really wanted to focus on our ability to drive down costs per well. And our guys have done a great job at that and we've achieved the goals that we've set for them. So now, we feel comfortable. So, we're going to exit the year at twice the deep rigs that we started the year with. And I think you'll see that kind of expansion of the rig, you'll see that as we go out kind of year after year. And so, that wouldn't be a surprise to me in terms of three rigs, six rigs. And then the next year, as you look into 2011, more likely, we'll be at 12 rigs. And then, you can probably double again after that.

And to get to the numbers that Jeff talked about. So, and then, if you run that through and volumes and whatnot, that's what it's going to take. Again, that's from the technical perspective but we've run a bunch of modeling in terms of; What does that do to the balance sheet? How do you fund that and whatnot? And we're really focused on -- to me, it's not how many rigs you run or how much your production. It's what you deliver on a per share basis.

So we can run real fast. We can run a lot faster than we're running but we'd have to issue a bunch of equity like some other companies that have done it, that are in shale plays. And we'd run those and we'd modeled it out and your NPV just comes out less. So, one of the things I learned is that the fewest shares you put out, the more likely your stock price is going to go up. So, more than likely, your stock prices will go up. So, we're trying to balance between what the organization is capable of doing, what the infrastructure will allow us to do. And again, on the infrastructure side, once we get to the 120 million a day plan in, plus some of the things we're doing next year, a lot of that is basically solved. So then, it's just adding on and we've got a plan to do that and it looks really good.

So really, it becomes, at that point in time; What can we do organizationally? And let me tell you, Ray Walker and his team up there, Joe Frantz, as Jeff talked about, this guy is a superstar and we're glad to have him. He fits right into the organization. Scott Roy is a terrific young man that is really just a star when it comes to being able to look at things more from the environmental and regulatory side, which I think will really help us. But still, Ray Walker, John Applegate, [Sikorsky,] Matt [Creary,] the rest of these guys are just doing a terrific job up there. So, I'm really getting more and more confident. I think, what do we have now, Jeff, 180 to 190 people up there?

Yes.

This whole thing with recycling came out of all of that. There was a lot of testing, a lot of people worked on that. Did a really good job from that group. So we're really building the infrastructure, these custom built rigs we've got. As Rodney said, go out and look at the Website and see how they walk around the pads. That's really remarkable. So all of that is in preparation of getting o 40 or 50 rigs here in three or four or five years. So when you take that you've got to couple it over, how should we -- what's going to be -- How can we make our shareholders the biggest winners? And so we tweak with that all the time in terms of how fast we should go.

And the good news is, from all this modeling, is we believe and again, a lot of it has to do with gas prices, that between asset sales, if you just look over the next five years. If you take asset sales, that we think we can accomplish and except to do any acquisitions, we won't have to issue any equity. We can do this with our existing equity base. And the good news is for the shareholders is, that all the upside that Jeff is talking about, it will accrue to all of us. And when I say, "All of us," I'm still the largest individual shareholder and I'm a pig and I want it all for myself. I don't want to share it, quite frankly, with a bunch of foreign company joint venture partners. Or I don't want to share it with a bunch of new shareholders, unless I absolutely have to. And that's about as blunt as I can say it.

Well, I appreciate the answer. I think that's what sets you all off from some of the other unconventional players. And the sell-side hasn't figured out yet that there's a lot of dilution that still has to occur for some of these shale plays to get done. But your measured pace is going to keep you from doing that. If you don't mind, I've got a question for maybe for Rodney or any of you all. But it really has to do with the change in the way reserves can be reported at the end of this year and whether or not you all have decided to report 2P and 3P reserves? And if not, why you would not?

Monroe, I'll take a shot at that. Range Resources and the rest of the industry are all kind of running around like chickens with their heads cut off, is the best way -- trying to figure out what to do. A couple things I think are important to note is that while the rules have "changed," there's a lot of unknowns in those rules that people are trying to figure out. And if you go to the SEC and ask them questions, they don't even know. So, Alan Parker who is our Senior Vice President of Reservoir Engineering and is just, really when it comes to this kind of stuff, has talked a lot of the chief reservoir engineers in these other companies. And they're all trying to figure out how to do all of this within the context. And there's a lot of questions being asked to the SEC and we're getting a lot of shrugs there.

So, all I can tell you is we don't know yet. And quite frankly, I think it's a pretty material thing. And we'll answer that question in December. And we're going to go to our Board and get -- whatever we do, it's going to be discussed and fully vetted at the Board. We're just not going to make that decision ourselves. More than likely, just to give you at least my view of it is, the Range way is to take it -- to go slower versus faster in all this. And we're going to continue to be very disciplined in terms of how we look at reserves, irrespective of some of the new rules and the vagaries that go along with that.

And my hope is that the rest of the industry takes a very disciplined approach at it. I'm a little concerned that they're not, for reasons that people can speculate on, but my hope is that the industry takes a very disciplined approach. If you look what happened in Canada, when they did this a moon or two ago, it was a little bit of a chaotic event. So, we're a little concerned there and we've looked at that. And so, hopefully, that answers your question but the blunt answer is we don't know yet.

Just as a follow on, not to dominate this. But from your understanding of the rules, would you have to demonstrate that you'd the cash flow to be able to develop these 2P and 3P reserves or some way to finance them before you could put them on the books?

Well again, the rules are vague. I can tell you one thing, that at Range Resources, we're not going to put things on the books unless we have a very good idea that we're going to drill them. Because I'm the one and Roger and I have to sign these little forms that if you screw up, you go to jail. So, I don't care what "the engineers" tell me but we're only going to put things in the engineering report that we are pretty convinced that we're going to drill up in a reasonable period of time.

Okay, thanks for the answers and great results.

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

Good afternoon and our team does too so can't agree more with a good hire there. Good afternoon. And I know Joe pretty well and our team does too, so can't agree more with the good hire there. As you think about -- just one quick question on third quarter and then fourth quarter kind of realizations in the Marcellus for gas and liquids? And as the MarkWest processing ramps up, how does that change? What was it currently and then how does that change?

David, as you can imagine, there's a whole lot of moving parts there. And let me give you a little bit of perspective in that. Right now, a fair amount of our gas is being processed in the southwest through a refrigeration plant, which it doesn't have the ability to strip out as much as of the liquids that the cryogenics plant does. So, once the cryogenic plant comes online, we will be able to receive a lot more money for those liquids than we have previously, which will be an uptick in the realizations that we're going to get from the Marcellus. So, that's kind of the big picture.

If you think about what happens is -- let me just kind of go through it again, the way I think through it, which is pretty simple. Is that when you take the gas through the plant, they're going to strip the liquids out. And now that the cryogenic plant will strip a bigger piece of it out and be able to get more money for that. And obviously, liquids today are on a relative value, much more valuable than nat gas. So, the more liquids you can take out and you get paid for them. So, it's a relative -- it's a huge high grade given the difference in what you're getting paid per BTU for gas versus liquids. So, that's the first thing.

Second thing is, is once the gas -- so once you strip out the liquids, the gas still has a relatively high BTU factor. And under our gas contracts and the way we sell our gas, we have been and will continue to get credit for the BTU's. We're selling BTU's, not just selling Mcf's. So, that's the other thing. So, basically three things. One, you get your raw gas. Then, you get your BTU uplift. And then, you get your liquid uplift.

So would a 40-barrels per million yield, that kind of declines off the 10-barrels per million be a reasonable assumption? And kind of 40% to 50% of crude oil price realizations be good long term?

Well, to give you a rough idea, the gas that goes through the the cryogenic plant, once it gets up and running, it will be about $0.75 to $1 relative increase versus Henry Hub.

Okay. Yes, I was just trying to model out liquids separately, so as we change oil and gas prices we get that real uplift in the higher oil world. But we can talk about it offline if I want to try to break that out.

Sure.

The other question, talking about acquisition opportunities and it seems like there's going to be some assets for sale in the Nora area. Is there any interest at all in adding acreage or adding producing assets around Nora?

Great question. We have an interest in adding and acquiring assets and Chad and his team continue to look at things all the time. Life has become a little bit more difficult for them because obviously, they're challenged in terms of, now we've got the little turbocharger from the Marcellus and the returns from that. So, that makes it a little tougher in terms of finding things that we think are going to be NAV accretive on a per share basis. That being said, if we can find high quality assets in our core areas, and clearly Nora is one of our core areas, we're going to take a hard look at it.

The other question is; Can we buy it at a price that we think is accretive to our shareholders. And what I mean there is that if we go out and buy something, like we have over the last five or six years, we'll fund the equity piece of that through issuing equity, more than likely to the market. So, then it has to survive that rigorous analysis. So, therefore, it's a challenge. But will we look at it? If it's in our core area and we think we can acquire it at a reasonable price and we feel like it's accretive to our shareholders sure, I think that's what you'd pay us for to do, is to do those types of things. And then the question is; Can we buy it at a price that works for us, given all of the vagaries and people's views of future gas prices and whatnot? But as those assets come on the market, we'll take a hard look at it.

Just like we're looking at things in the Barnett now and we're looking at things in the Marcellus right now. But yes, that being said, we haven't done an acquisition for nearly two years. So again, I think that gives you a little bit of idea of we're going to be really disciplined. And again, it all gets back to what really matters to us and that's really the per share or the stock price. And being the biggest producer or having the most rigs or having the biggest acreage position, all of that kind of gobbledygook just absolutely means nothing to us.

Okay. And as you think about the leasing decision for equity, it's small dollar amounts but how do you think about using your equity or what's the seller of the acreage? Are they asking for equity as opposed to cash or how are you thinking about issuing equity for acreage in the Marcellus?

Yes, that's a great question. In most cases, the sellers are asking for it and so that's why we've done it. And in each of the cases -- let me just back up. In the Marcellus, we're not buying, what I call, any trend acreage in the Marcellus, haven't been for almost two years ago now, Everything we're buying is very targeted. It's within something that we have a very clear view geologically on what we're doing. And it's stuff that we think is very promising in terms of the potential. And we don't own all of the acreage in all the areas that we think are highly prospective. And we don't have enough money to acquire all that acreage, quite frankly, and we never will acquire it all.

But in and around some of our very, very key areas, that's where we're spending our money. And the good news is with this -- there's one good thing about the recession has been that the acreage prices have cooled off quite a bit. And we've been able to pick up a fair amount of acreage, again, right in between a bunch of key leases and whatnot and picking up the acreage. And so, that's been one good part about it. The other thing about Appalachia that is different, than say the Barnett Shale play in particular, is that there aren't 20,000-acre ranches in Pennsylvania. These are relatively small farms, in most cases. So, the leasing is very, very tedious. It takes a lot of land people. And that's why our -- and we built this acreage position over a 25 year period. We were fortunate to have some acreage in the beginning of the play that has happened to be in the middle of it. But we've built on extensively and we'll continue to do that.

The other thing we're doing is we're discussing with a number of different Marcellus players out there about trading acreage. And they try to -- they block up their positions, we block off ours because clearly that's beneficial from a drilling and operating expense perspective. So, what we're doing some of those, we've done two or three so far and we've got two or three more in the works that we're working on.

All right, thanks.

Thank you. We are nearing the end of today's conference. We will go to Marshall Carver of Capital One Southcoast for our final question.

Yes, thank you. One question, you added $40 million to the acreage budget and haven't changed your 900,000-acre position in awhile. Is that $40 million increase going mostly to the Marcellus or are you adding some in the Barnett too or just trying to get a feel for where that increase in acreage is going.

Most of it is going in the Marcellus but some of it's going in the Barnett. More than 50% of it is going in the Marcellus. And in terms of updating the numbers, we haven't updated the numbers in awhile. And no real reason, other than -- and I think the key thing is is that, in some cases, we're trading acreage and we end up with a few more acres remaining or a few less acres, depending on the relative quality of the acreage. The other thing is, as we've continued to drill wells, we've continued to high grade it. I think we actually, just last week or the week before actually, sold off, I don't know, 10,000 or 20,000-acres in an area that we just didn't think we could get to for 10 plus years. So, we actually sold that off and that money will be recycled into some of what we consider our A areas too.

So the acreage number is going up and down. It could go down, it could go up, it could go sideways for awhile, unless we do something that's pretty material. And again, we do, from time to time, have people with large blocks of acreage that have come to us and because we are the pioneer of the play and they see our results and how well we've done. They've asked us to be their partner. And that's challenging because again, because if you think through it, I'd rather be spending our talent on acreage where we get 100% benefit versus acreage we're getting let's say 50% benefit or 60% benefit. Not that we don't look at those but we evaluate those as well. So, it's just all that kind of gobbledygook together.

Okay, thank you. And are you adding sort of equally in northeast and southwest PA or could you give any color on that?

We're adding some in the northeast but primarily in the southwest.

Okay, thank you.

And just to answer that, Marshall. The reason is that, is obviously, we've drilled more wells there. And again, not the smartest bulb in the package here but when you drill a good well and if there's some acreage that -- we've got most of it tied up but there may be some of it that needs prospective. So, we'll run out and try to pick that up. And again, trying to continue to block up the acreage. And again, one of the keys is blocking up the acreage because it allows you to do the recycling, like Jeff talked about. It's cheaper in terms of roads and pipelines all the other stuff. And we've really encouraged all of the operators in the Basin to really block it up. Because we think that's really -- environmentally, it's the best way. And it's going to drive up the production the quickest in the Basin, as well, in terms of pipeline and infrastructure. So, it's all part of the master plan.

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

Well, thank you all for being on the call. I think we ran over a bit and I apologize for that. There's some great questions and we try to be as transparent as we can at Range. If you didn't get your answer -- get an answer or a question or if you thought our answer wasn't clear enough to you, feel free to call Rodney and he'll get you to the right person to get those questions answered for you. We really appreciate the time. I'll just sign off, given that we've run over so much. Thank you very much.

Thank you for your participation today in the conference. You may disconnect your lines at this time.