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Executives

Rodney L. Waller – Senior Vice President & Assistant Secretary

John H. Pinkerton – Chairman & Chief Executive Officer

Roger S. Manny – Executive Vice President & Chief Financial Officer

Jeff L. Ventura – President & Chief Operating Officer

Analysts

Thomas Gardner – Simmons & Company

Ronald Mills – Johnson & Rice

Joseph Allman – JPMorgan

Monroe Helm – CM Energy Partners

David Heikkinen – Tudor Pickering Holt

Marshall Carver – Capital One Southcoast

Range Resources Corp. (RRC) Q3 2009 Earnings Call October 22, 2009 1:00 PM ET

Operator

Welcome to the Range Resources’ Third Quarter 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.

Rodney Waller

Thank you, operator. Good afternoon, and welcome. Range reported results for the third quarter of 2009 with record production, leading 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’re encouraged with this ability to grow production, we’re more focused on achieving those targets at an optimum cost structure on per share basis to maximize shareholder values. I think you will hear those same principles 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’s now available on the home page of our website, or you can access it using the SEC’s EDGAR system. In addition, we posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDA, 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 the detailed information of our current hedge position by quarter. Also posted on home page 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 roadshows 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 Investor’s DUG conference in Pittsburgh earlier this week. This presentation is posted on the website, and 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’s conference in New Orleans on December 9.

Now, let me turn the call over to John.

John H. Pinkerton

Thanks, 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 the guidance. The 13% increase includes the impact of selling our Fuhrman-Mascho field effective June 30, 2009.

If we hadn’t sold Fuhrman-Mascho, production would have been a 17% increase, this marks the 27th consecutive quarter of sequential production growth. The driver for this was a 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 built 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 offering costs, as they’re averaging $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, build and high-grade our acreage position, build out infrastructure, and bring down our well cost. In addition, we continue 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, and particularly, 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, who will review our financial results

Roger S. Manny

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. 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 remain 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. 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 of 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 analyst consensus estimate of $1.04.

Quarterly EBITDAX of 198 million was 22% lower than the 254 million earned in the third quarter of ‘08. The 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 a 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 counter-intuitive of 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 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’re 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 analyst consensus methodology for the third quarter, were $41 million, or $0.26 per fully diluted share. That’s $0.04 higher than the analyst consensus estimate of $0.42.

The quarterly GAAP after tax net loss was 30 million. And 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 analyst earnings, cash flow, net tax, and cash margins.

As I mentioned earlier, the third quarter this year represents the first full quarter following our second quarter Fuhrman asset sale. Not only we were able to make up the lost production volume from the sale, we were able to replace the production from substantially lower operating cost areas, And the asset sale, combined with continued downward pressure in service costs, is what led to the third quarter direct operating expense figure of $0.75 per mcfe.

The good news on the cost gets even better when you add cash production taxes to the total. Now, because production taxes are based on well head 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.

Now 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 maybe 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 on our reserve for bad debt of $1.1 million.

These items total $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 is primarily a reflection of the increase in the value of Range common stock held in the deferred comp plans. It does not represent the contribution to the plan, or a 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 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 ‘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 the sale came from areas such as the Barnett and Marcellus, where the depletion rates are 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 return projects, and that has reduced incremental production in 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 will 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 a multi-billion dollar ceiling test write-down.

One of the primary drivers of our improving capital efficiency at Range is our practice of allocating capital on a real-time 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’re seeing our best returns, and requires all Range divisions to continually improve their returns to be competitive.

We are witnessing the fruits of the flavor as we’re producing solid double-digit production growth this year without acquisitions, and despite asset sales, with fewer than half 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 that have near-term expirations.

This prompts us to continually reexamine the status of our leasehold positions, and take additional impairments to our unproved properties in areas where we deem the acreage less valuable, or likely to expire. Now 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 lifecycle, and our drilling activity increases. Investors wishing a more extensive explanation of the unproved property impairment process for successful efforts 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 CliffsNotes 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. Now 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 deductions. We anticipate a 36% tax rate for all of 2009.

Range continues to benefit from its 2009 hedges, and we have approximately two-thirds of our fourth quarter gas production hedged at a floor price of 7.79 Mmbtu, and a ceiling price of 8.53. We have 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 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 per Mmbtu.

The best news on the balance sheet front this quarter is that there is no news. Overall debt-to-capitalization is essentially flat at 42%, 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, wholly 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.

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 and 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 re-determination.

Range completed a significant asset sale last quarter, and we’re 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 the 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’re 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, rigorous capital spending discipline, and prudent assets 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 a bit 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 absolute basis, but on a per share basis. Some quarters stand out for what happened, and some quarters 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 reductions, cash flow, and our hedging position, all the while, respecting the balance sheet.

So John, I’ll turn it all back you.

John H. Pinkerton

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

Jeff L. Ventura

Thanks, John. I’ll begin my reviewing productions. For the third quarter, production averaged 437 million per day, a 13% increase over the third quarter of 2008. This represents the highest quarterly production rate in the company’s history and the 27th consecutive quarter 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 Midcontinent 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 drilling completed 60 horizontal Marcellus Shale wells. 54 of the wells are currently on-line, 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 slot 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 resulted a 46% rate of return and cost to sign and develop of $0.95 per Mmcfe. At a $7 gas price, the rate of return increases to 75%. We believe this is the best rate of return in finding any new development cost 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 three to four Bcfe range. To-date, our average well has been about 4.4 Bcfe, which is above the top end of the range. I would 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 three to four 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 de-risked even more of Range’s acreage.

Using just the 390,000 net acres, within what we believe is a low risk, high-chance-of-success, de-risk 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’s done. Range is currently a 2.7 Tcf company, therefore, we have the potential to grow significantly from just this one play, and 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’ve previously drilled and tested.

We also see significant upside potential in both the Utica Shale and Upper Devonian Shale on our portions of our acreage. Prior to year-end, we plan to spud two horizontal wells to test each of these concepts. At year-end 2007, Range’s Marcellus production was about eight million per day net. At year-end 2008, we’re 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 wanted 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 will flow 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. It also eliminates and 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 the 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 linemen. I believe that we have one of the best shale teams in the industry. We continually look at adding first-round draft picks for 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 U.S. 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 our 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 other two 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 infill wells are performing on par with the original wells, and in some cases, drilling the infill is improving the original well on the spacing unit. CPM 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 tight 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 Brea Sands 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 de-risked 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 110 million at the beginning of the year to about 130 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 quarter, 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 three major properties, the Marcellus and the Barnett Shales, and Nora, ranges from about $1 to $1.50, and the LOEs 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 U.S.

Range has consistently delivered top-tier organic production or reserve growth with one of lowest cost structures in the business. This is a direct result of our simple strategy of strong, organic growth, a top-quartile cost structure or better, and in addition, consistently building and high-grading our inventory, coupled with one of best teams in the industry.

We believe Range today has more upside, and lower risk upside, than in any time in the company’s history. With our inventory, we have the opportunity to grow the company more than tenfold, 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, John.

John H. Pinkerton

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 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 account both the asset sales and the drilling results today, we have increased our full year 2009 production growth target from 10% to 13%. Given our reduced capital program, we focus 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 a shallow decline curve, in particular, our tight gas sand properties in Appalachia and West Texas on a decline of roughly 10%.

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 to see much of a return on that. Beginning on 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’re 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 the 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 2009, our cash flow and completed asset sales should be more than adequate to fund our CapEx program. After closing the Fuhrman-Mascho sell, 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 cost, 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 drive 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, Marcellus production [natural] gas range is now 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 cost in southwest PA to roughly $3.5 million per well, as Jeff mentioned. In addition to 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 infrastructure build-out is growing 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 two, our first two horizontal wells in northwest PA or northeast PA that offset two of our best vertical wells. We have a very large acreage position in northeast PA covering roughly 350,000 acres. Third, we have spud our first Utica horizontal well, and fourth, we should spud shortly our first Devonian shale horizontal test. These four wells are important, because if they’re 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. I will work it 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. Taking 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 are planning to double the Marcellus production in 2010. Therefore, we’re 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 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 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 sizable acreage block, or producing property package in one of our key project areas.

And certainly, 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 crude 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 commitment by all 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.

Question-and-Answer Section

Operator

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

Thomas Gardner – Simmons & Company

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 northeast portion of the play?

Jeff L. Ventura

This is Jeff. Let me take and crack at that. Yeah, 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 made over 6 million per day from a vertical well, so we have high hopes for that and the other one’s offsetting also an excellent vertical well that made over 2 million per day. They’re drilling simultaneously, they’re already at significant depth. So I feel comfortable we’ll have results by the end of the year.

We’re already preplanning, 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 high I have good hopes for, high hopes for and I expect it will come online towards the end of the next year, with good results for 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.

Thomas Gardner – Simmons & Company

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?

Jeff L. Ventura

Yeah, well, we have roughly 2 million acres in the basin. When we talk about 1.4 million acres for the Marcellus that’s 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 high-graded 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 and 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 the play several years back, we targeted different areas predominantly in 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 it’s been very robust. And we continue to target basically those same areas.

John H. Pinkerton

Yeah, Tom, and this is John, I think that’s Jeff’s perspective is more, let’s say, from a geological perspective. The other perspective is kind of the business perspective. And as, 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 in natural gas in the State of New York. That didn’t mean a lot, but we’re still 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 look at this play. And there is no doubt in our mind that New York, was going to be more challenging from a regulatory perspective. It always has been, and in my view, always will. 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 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 the other plays. You got to take your technical work, and overlay with what you think the business risks are. And quite frankly, when we did that, New York was not one of the ones that, that popped out, where we 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 think that it’s bad, we just think Pennsylvania is better.

Thomas Gardner – Simmons & Company

Got you and 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.

Operator

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

Ronald Mills – Johnson & Rice

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

John H. Pinkerton

Well go ahead.

Jeff L. Ventura

John and I are battling on who’s going to answer, we can both chime in. I guess 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 all makes a difference. Where we are is in 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, where 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, or?

John H. Pinkerton

Yeah, I think and again, I think the key here is that clearly, over the next year or two, the major driver is going to be the southwest for us. I mean, 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’s 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, and we’ve got a fairly blocky acreage position, so it’s going quite well, just like it does in the Barnett or Woodford, or any other plays that we’re in terms of horizontal drilling. So, it’s become like clockwork.

The northeast, as you move away and again, you 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 Renz well, our first well drilled in the Marcellus isn’t too far away from the first oil drilled in 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 remember it.

So, because of that, you got all the infrastructure and all 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, blah blah blah blah. So again that 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, that’s again, that’s one of the reasons why we’ve been able to drive down costs, because now you’re getting competition for services, things are more routine, blah blah blah blah blah.

So, and again, all that relates to how you allocate capital, mean, we can go faster in drilling in the southwest than we can in 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 the other stuff you have to think about, that’s where we’re focused.

That being said again, like Jeff said, there’s enormous, we’ve got 350,000 acres. We’re one of the largest leaseholders in the northeast and people forget about it that all the time. So, we’re really excited about these two wells, to say the least. Hopefully and 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.

Ronald Mills – Johnson & Rice

Okay, and then from the Utica standpoint, and/or the upper Devonian, and obviously, you’re seeing the upper Devonian in your Marcellus wells. But from an aerial extent, or from an acreage standpoint, how much of Utica’s acreage do you think you end up with some Utica potential obviously, depending on some test wells being successful.

Jeff L. Ventura

Yeah. 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 Shale, we think it’s more prospective on the western side, and a lot of our acreage, we think, has potential for that.

So, the combined, they offer really significant upsides. So, be interesting test 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 first quarter of next year.

Ronald Mills – Johnson & Rice

Okay, great. I’ll let someone else jump in. Thank you, guys.

Operator

Thank you. Our next question comes from the line Mr. Joe Allman with J.P. Morgan. Please proceed with your question.

Joseph Allman – JPMorgan

Thank you. Good afternoon, everybody.

John H. Pinkerton

Hi, Joe.

Jeff L. Ventura

Good afternoon.

Joseph Allman – JPMorgan

Hey, 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?

Jeff L. Ventura

Yeah. It’s a very significant, because when you have to truck water, it’s expensive. Truck it, and then pay for the disposal facility. You’re looking at savings per well, literally, on the order of a couple hundred thousand dollars 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 really want to stop and talk about that point, because a year ago, most people said 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 wells? Well, none of them have 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 all of the water issues.

Joseph Allman – JPMorgan

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

Jeff L. Ventura

Yeah, 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 the trucking, you’re looking at LOEs for Marcellus, really of less than a dime per mcfe. So as we continue to ramp and build Marcellus, and you add that into the rest of the company, it’s going to continue to drive down our LOEs, coupled with the fact that part of our strategy is building high-grading inventory.

So, we’re focusing on our more efficient projects that not only have a 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 us, even though as good as Range has been, I think you’re going to see even better improvements, really, going forward.

John H. Pinkerton

And Jeff, this is, hey sorry Joe, let me interrupt you. Jeff, let me ask a question: then why the hell that our DD&A rate go up?

Jeff L. Ventura

Well…

John H. Pinkerton

Let me answer that, Jeff.

Jeff L. Ventura

[No way] let me chime after you’re done, but go ahead.

John H. Pinkerton

And let me give some, Roger, I think, went through the technical accounting, and probably think mumbo-jumbo if you want to call it that. But let me give you a big picture, and kind of some business man’s perspective is that: if you think one is, we’re on successful effort, so, we don’t do things, when we calculate DD&A, we do it by property pool. So, all the Marcellus is a pool by itself. I mean 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, as things change within those pools, it changes the DD&A rates, and as you change 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 for $212 million, and sold it for 180-something million. So, that’s an A+ check-the-box for all that, but when we sold it, it was still, was a relatively low, even though it had a really high operating cost, over $2 bucks an m, 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, with Marcellus. Now let’s talk about that for a bit, and let me just zero in on the Marcellus, is that you think about what the Marcellus is that since October of 2004, we’ve spent a whole bunch of dough, almost $1 million in the Marcellus. And we spent enormous amount of money on science, and we 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 pools, and you set your DD&A rate for that pool, okay. And even though production’s 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 don’t do is every quarter, as we drill more wells, change our DD&A rate in the Marcellus. If we’d 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 as Roger said, it’s too early to tell, we don’t have the numbers. Al and his team are still working on all the reserve numbers, and you got do all the costs and year-end, blah blah blah. But you’ll see that come back down, so as Roger mentioned, that was a temporary kind of 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 rates 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 business man’s view of it. And the good news is, I think, over time, as we drill 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 then the D&A rate and the finding and development costs will begin to merge.

Joseph Allman – JPMorgan

Okay, 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?

Roger S. Manny

Yeah, I mean, just looking water-hauling disposal cost 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.

Joseph Allman – JPMorgan

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

Jeff L. Ventura

No, the – like I mentioned earlier, just clarify, the pipeline for that won’t be up and running till the end of 2010. So, we’ll drill them, we’ll test them, and then we’ll shut ‘em in and you’ll see us do some drilling around them. But that won’t come on to the batch around the end of 2010. And then, 2011, you’ll see a significant ramp-up up in that area.

Joseph Allman – JPMorgan

Okay. Very helpful. Thank you.

Operator

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

Monroe Helm – CM Energy Partners

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 the limiting factor?

Jeff L. Ventura

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 in January, February, but roughly speaking, at this point in time, you’ll see is 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 de-risk box, we think we have the potential to drill significant number of wells and develop, really over a 11.6 Tcfe, just on what we’ve proven up so far.

So you’re going to see significant growth, but the important part I think we understand, 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 a multiple Tcf play, there is 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.

John H. Pinkerton

Yeah, and great question Monroe, and I think this year we really and probably made it a large degree, and I’ll let Jeff take it. But we really wanted to focus on our ability to drive down cost 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. Just 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 in 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 number that Jeff talked about.

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

So, we can run real fast. We can run a lot faster when we’re running, but we got to issue a bunch of equity, like some other companies that have done that are in shale plays, and we’ve run those, and we’ve modeled it out, and your NPV just comes out less.

So, one of the things I’ve learned is that the fewer shares you put out, the more likely your stock price is going to up. So, more than likely, your stock price will go up. So, we’re trying to balance between what the organization is capable of doing, what the infrastructure allows to do. And again, on the infrastructure side, once we get the 120 million day plan in, plus some of 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 we can 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 regulatory side, which I think will really help us. But still, Ray Walker, John Applegat, Gorsky, Matt Curry, 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…

Jeff L. Ventura

Yup

John H. Pinkerton

190 people out there. This whole thing with the recycling came out of all that. There was a lot of testing. A lot of people worked on that, did really a 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 that is in preparation of getting the 40 or 50 rigs here in three or four, five years. So, when you take that, you got to couple it over, what’s going to be, how can we make our shareholders the biggest winners? And so that we tweak with that all the time, and 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 the saving except to do any acquisitions, we won’t have to issue any equity. That we can do this with our existing equity base, and the good news is, for the shareholders is, is that all the upside that Jeff’s talking about, it’ll 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 with a bunch of new shareholders, unless I absolutely have to. So, and that’s as about as blunt as I can say it, okay?

Monroe Helm – CM Energy Partners

Well, I appreciate the answer. And I think that’s what could shovel 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, I guess, maybe for Rodney 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?

John H. Pinkerton

Monroe, I’ll take a shot at that. Range Resources and the rest of the industry are all kind of running around with chickens with their heads cut off is the best way and trying to figure out what to do. A couple of things I think are important to note is that while the rules have, quote, 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 Farquharson, who is our Senior Vice President of Reservoir Engineering, and is just brilliant when it comes to this kind of stuff, has talked to a lot of the chief reservoir engineers in these other companies. And they’re all trying to figure out how to do all 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 is 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, 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 of, 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, but and we’ve looked at that, and so hopefully, that answers your question, but the blunt answer is, we don’t know yet.

Monroe Helm – CM Energy Partners

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

John H. Pinkerton

Well, again, the rules are vague. I can tell you one damn 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. 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, quote, the engineers tell me, but we’re only going to put things in the engineering report that we are pretty damn convinced that we’re going to drill up in a reasonable period of time.

Monroe Helm – CM Energy Partners

Okay, thanks for the answers, and great results.

John H. Pinkerton

Thanks.

Jeff L. Ventura

Thanks.

Operator

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

David Heikkinen – Tudor Pickering Holt

Good afternoon, Joe pretty well and our team does too just 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, I mean, how does that change, what was it currently, and then how does that change?

John H. Pinkerton

David, there’s, 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 is, it doesn’t have the ability to strip out as much of the liquid that the cryogenic plant does. So, once the cryogenic plant comes on-line, 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 we take the gas through the plant, they’re going to strip the liquids out, not at the cryogenic plant. We’ll strip a bigger piece of 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, 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, the 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 will get credit. We have been, and we’ll continue to get credit for the btus. We’re selling btus, not just selling mcfs, 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.

David Heikkinen – Tudor Pickering Holt

So with a 40 barrels per million yield 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?

John H. Pinkerton

Well, to give you a rough idea, the gas that goes through the plant, through the cryogenic plant, once it gets up and running, it will be about 75 to a dollar relative increase, versus Henry Hub.

David Heikkinen – Tudor Pickering Holt

Okay. Yeah, 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 well. But we can talk about it off-line, if I want to try to break that out.

John H. Pinkerton

Sure.

David Heikkinen – Tudor Pickering Holt

The other question, talking about acquisition opportunities, 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?

John H. Pinkerton

Great question. We have an interest in acquiring assets, and Chad his team continue to look at things all the time. Life’s become a little bit more difficult for them, because obviously, they’re challenged in terms of, now we got the little turbo charger from the Marcellus, and the returns from that. So, that makes it a little tougher in terms of buying 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’s one of our core areas, we’re going to take a hard look at. 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, is that, if we go out buy something like we have over the last five or six years, now, we’ll fund the equity piece of that. I mean, 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 the way we look at it, if it’s in our core area, and we think we can acquire it a reasonable price, and we feel like it’s accretive to shareholders, sure, I think that’s what you pay us for to do, is to do those types of things. And then the question is, can we buy it a price that works for us, given all the vagaries, and people, future year gas prices and what-not. But as those assets come on the market, we’ll take hard look at it.

David Heikkinen – Tudor Pickering Holt

Okay.

John H. Pinkerton

I mean, we’re looking at things in the Barnett now, and we’re looking at things and in the Marcellus right now. So, but yeah, I think that being said, we haven’t done an acquisition for nearly 10 years. So, again, I think, to gives you a little bit of an idea, we’re going to be really disciplined. And again, it all gets backs to what really matters to us, is that 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.

David Heikkinen – Tudor Pickering Holt

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, I guess, 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?

John H. Pinkerton

Yeah, it’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 now. Everything we’re buying is very targeted, it’s in 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, very key areas, that’s where we’re spending our money. And the good news is, with this, the one good thing about the recession has been is that prices, 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 what-not, and picking up the acreage. And so that’s been one good part about it.

And the other thing about Appalachia that is different than, let’s 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, takes a lot of land people. And that’s why our acreage position and we’ve built this acreage position over a 25-year period. We were fortunate to have some acreage in the beginning of the play that just happened to be in the middle of it where we’ve built on extensively in that, and we’ll continue to do that.

The other thing we’re doing is that we’re discussing with a number of different Marcellus players out there about trading acreage and they try to block up. They block up their positions, we block up ours, because clearly, that’s beneficial from a drilling and operating expense perspective. So, 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.

David Heikkinen – Tudor Pickering Holt

All right. Thanks, all.

Operator

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

Marshall Carver – Capital One Southcoast

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

John H. Pinkerton

Most of it’s going in the Marcellus, but some of it’s going in the Barnett. More than 50% of it’s going in the Marcellus. So, in terms of updating the numbers, we haven’t updated the numbers in a while, and no real reason other than and I think the key thing is that, in some cases, we’re trading acreage.

We end up with a few more acres, and they end up with a few less acres, depending on the relative quality of the acreage. The other thing is, as we continue to drill wells, we continue to high-grade it. I think we actually, just last week or a week before, actually sold off , I don’t know 10 or 20,000 acres in an area that we just didn’t think we’d get to for 10-plus years. So, we actually sold that off and that money will be recycled into some of our, what we consider our A-areas too.

So the acreage number’s going to go up and down could go down, could go up, could go sideways for a while, unless we do something that’s pretty material. And 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 it, they’ve asked us to be their partner. And that’s challenging, because again, if you think through it, I’d rather be spending our talent on acreage, where we get 100% benefit versus acreage where we’re getting, let’s say, half 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.

Marshall Carver – Capital One Southcoast

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

John H. Pinkerton

We’re adding some in the northeast, but primarily in the southwest.

Marshall Carver – Capital One Southcoast

Okay, thank you.

John H. Pinkerton

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 probably pick that up. And again, trying to continue to block up the acreage, and key 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, and all the other stuff. And we’ve really encouraged all the operators in the basin to really block 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.

Operator

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.

John H. Pinkerton

Well, thank you all for being on the call. I think we ran over a bit, and I apologize for that. Just some great questions, and we try to be as transparent as we can at Range. If you didn’t get an answer to your 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.

Operator

And thanks for your participation today in this conference. You may disconnect your lines at this time.

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Source: Range Resources Corp. Q3 2009 Earnings Call Transcript
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