Range Resources Corporation Q4 2009 Earnings Call Transcript

| About: Range Resources (RRC)

Range Resources Corporation (NYSE:RRC)

Q4 2009 Earnings Call Transcript

February 24, 2010 1:00 pm ET

Executives

Rodney Waller – SVP & Assistant Secretary

John Pinkerton – Chairman & CEO

Roger Manny – EVP & CFO

Jeff Ventura – President & COO

Analysts

David Kistler – Simmons & Company

Ron Mills – Johnson Rice

Marshall Carver – Capital One Southcoast

David Heikkinen – Tudor Pickering Holt

Mike Scialla – Thomas Weisel Partners

Dan McSpirit – BMO Capital Markets

Leo Mariani – RBC Capital Markets

Operator

Greetings and welcome to the Range Resources 2009 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. Thank you. Mr. Waller, you may now begin.

Rodney Waller

Thank you, operator. Good afternoon and welcome. Range reported results for the calendar year 2009 with record production, leading the consensus number and setting a firm platform of continuing growth at low cost with high rates of return for 2010.

The fourth quarter marked our 28th consecutive quarter of sequential production growth. Range has now completed its seven years of quarterly sequential production growth, with 2009 finding and development costs at the lowest in the company’s history. Although we are encouraged with our resource base to continue to grow production and reserves, we are more focused on achieving those targets at an optimum cost structure on a per share basis to maximize shareholder value. I think you will hear those same things reiterated from each of 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, 10-K 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 margin, and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. Tables are also posted on the website that will give you the detailed information of our current hedge position by quarter.

Secondly, we will be participating in several conferences in the coming weeks. Check our website for a complete listing for the next several months. Jeff Ventura just spoke at Enercom’s Conference in San Francisco last week, and his remarks are still on the website. Next week we will be attending the Simmons Energy Conference in Las Vegas, the JPMorgan High Yield Conference in Miami, Thomas Weisel Partners Energy Conference is Denver, and we will finish up March with the Raymond James Conference in Orlando, the Wells Fargo Energy Forum in Boston, and finally see everyone in New Orleans at the Howard Weil Energy Conference at the end of the month.

Now let me turn the call over to John.

John Pinkerton

Thanks, Rodney. Before Roger reviews the financial results, I will review some of the key accomplishments for 2009. Overall, we are very pleased with 2009 results. On a year-over-year basis, production rose 13%, beating the high end of our guidance.

Fourth quarter production averaged $457 million a day, a record high for Range. It also represented the 28th consecutive quarter of sequential production growth. I should note that no other company in our peer group, to our knowledge, has achieved 28 consecutive quarters of sequential production growth. I believe this is a vivid testimony to the quality of our operating teams we have in each of our divisions.

At year-end, proved reserves totaled 3.1 Tcfe, an 18% increase over 2008. Reserve replacement was 486% from all sources, including price revisions. Our FD&A costs averaged $1 an Mcf, the lowest in our history. Our drilling program alone delivered 540% reserve replacement at a cost of $0.69 per Mcfe, again the lowest in our history. Based on what we’ve seen today, these look to be some of the results of our peer group.

We combine excellent growth in production reserves with low finding and development costs. That’s the hard part of our business that combined high growth with low cost. Again, this performance is attributable directly to our very talented technical teams in our divisions. Most importantly, production and reserves per share on a debt adjusted basis again increased over 10%. This marks the fifth consecutive year that we have achieved double-digit production and reserve growth per share.

In 2009, we completed $219 million of asset sales. Over the last three years, we sold over $0.5 billion of properties. We would believe periodically selling our more mature properties have several benefits. First, it helps focus us on our higher growth opportunities; second, provides additional capital for our high return activity; third, helps high grade our property base; and fourth, asset sales reduce the need to issue equity.

From a financial perspective, we continue our disciplined and simple approach. Total debt declined by $83 million in 2009, and we ended the year with approximately $1 billion of liquidity under our bank line. As the largest individual shareholder of Range, I’m very pleased that the average shares outstanding rose only 1.8% during 2009.

I’m also pleased that with some of the things that we didn’t do in 2009. In particular, we didn’t complete a single producing property acquisition during the year, while we continue to evaluate a number of many opportunities. We concluded that none of them were accretive on an NAV per share basis. We also considered but did not pursue a joint venture of our Marcellus Shale acreage.

While shale play joint ventures seem to be the current rage, we view them simply as asset sales. Given that we believe that Marcellus has some of the best, if not the best, economics in the E&P business today, we are a buyer, not a seller of the Marcellus. Our strategy has been to sell our higher cost, lower growth, more mature properties and recycle the proceeds into our lower cost, higher return projects like the Marcellus, Barnett and Nora.

I would not completely rule out Range doing a Marcellus JV. If we did one, it would have to be at a substantially higher price than any of the previous deals, including the recently announced Anadarko-Mitsui joint venture. I want to keep – at the end of the day, I think it’s our job is to keep all Marcellus resource potential for Range’s shareholders. In addition, diluting our NAV in resource potential per share, JVs also dilute our technical teams.

At Range, we own roughly 100% working interest in nearly all of our Marcellus acreage and have an average royalty of roughly 15%. So when our technical teams go out and drill Marcellus well, we gain 85% of the production reserves and cash flow. By entering [ph] into a JV, our technical teams would have to drill significantly more wells to achieve this high net result. At Range, we prefer to keep things simple also. Having a partner in thousands of future Marcellus wells that we anticipate drilling over the next five to 10 years will maturely complicate our business and make us less efficient.

With that, I’ll turn the call over Roger to discuss our financial results. Roger?

Roger Manny

Thank you, John. Range ended 2009 on a high note with a very solid fourth quarter operating and financial performance. Cash flow for the fourth quarter exceeded last year’s even though oil and gas prices were lower. We lost significant production to asset sales during the year, but oil and gas production still set a new record high for the fourth quarter and year. Direct operating cost remains well below last year, and our record drill bit growth did not come with the expense of the balance sheet or the shareholders, as we ended the quarter and the year with less debt, more liquidity, and a share count very close to where we started.

Oil and gas sales for the fourth quarter, including all settled derivatives, came to $277 million, a 9% increase from last year, as our increase in production won out over the 4% decline in realized price. Cash flow for the fourth quarter of 2009 was $188 million, up 14% from last year and up 10% from last quarter. Cash flow per share for the quarter was $1.18, $0.02 per share higher than the analyst consensus estimate of $1.16.

Quarterly EBITDAX was $215 million, 12% higher than last year. Cash margins for the fourth quarter were $4.34 per Mcfe, and that’s the third consecutive quarter of improved margins. Year-over-year, while prices declined by $0.27 per Mcfe, cash margins only declined by $0.07, thanks to reductions in operating costs. Fourth quarter cash direct operating expense was $0.75 per Mcfe, 20% below the fourth quarter of last year.

And to further illustrate our lower operating cost on an absolute dollar basis, direct operating cost was almost $3 million less in the fourth quarter of this year than last year even though production was 13% higher. Expect directing operating cost to hover around the $0.75 per Mcfe level for the first quarter of next year until the impact of our pending asset sales take hold, after which direct operating cost per Mcfe should drop into the mid-to-high $0.60 range.

Reflecting lower oil and gas prices, production and ad valorem taxes for the fourth quarter were lower on an absolute and unit cost basis, coming in at $0.21 per Mcfe versus $0.27 last year. Exploration expense for the fourth quarter, excluding stock-based compensation, provided a pleasant surprise of just over $9 million compared to the $11.5 million last year.

Exploration expenses tend to be a bit front-loaded in a new budget year. So looking ahead into the first quarter of 2010, exploration expense is likely return to the $17 million to $19 million range. This is due to increased seismic purchases, delayed rentals, and exploratory drilling.

General and administrative expense adjusted for non-cash stock comp and severance accrual totaled $0.50 for the fourth quarter, down $0.03 from last year just as we saw a spike in G&A during the third quarter due to severance obligations associated with the closing of our Houston office, we expect another spike in the first quarter of 2010 related to severance cost associated with the pending sale of our Ohio shallow tight gas sand asset. First quarter 2010 G&A, including severance, should be in the $0.65 to $0.67 per Mcfe range, before retreating back to the low $0.50 range for the rest of the year.

Interest expense on an absolute basis was flat with the prior two quarters, thanks to lower debt levels. And on an Mcfe basis, interest expenses drifted down, tracking the increase in production with interest per Mcfe for the quarter of $0.73. It’s worth noting that following the Ohio asset sale, Range will have 90% of its debt funded at a fixed rate of 7.4%. This positions the company well should interest rates begin to rise.

Fourth quarter abandonment and impairment of unproved properties totaled $29 million, which includes impairments associated with the closure of our Houston office and abandonment of certain non-core unproved acreage in the Barnett Shale. Going forward, we anticipate that quarterly unproved impairment will range between $14 million and $16 million per quarter.

Before we get to the bottom line income figures for the quarter, I’d like to explain some of the unusual income and expense items flowing through the income statement. On the revenue side, we booked a $10.4 million gain on the cash sale of non-core undeveloped acreage in Pennsylvania, which is excluded from our non-GAAP adjusted earnings.

This item helped to offset some of the non-cash expense and impairment items, such as the $10 million charge taken in connection with our soon-to-be decommissioned Marcellus refrigeration gas processing plant, a $900 million proved property impairment on a producing deal included in the Ohio asset sale package, and a $6 million non-cash write-down of our equity investment in our Appalachian drilling company.

While unscheduled charges to earnings are never welcome, the charge for decommissioning the Marcellus refrigeration plant had a silver lining, which is we need the physical space the refrigeration plant is sitting on to construct and expansion to our cryogenic processing capacity.

The good news here is that, one, the Marcellus play is exceeding our expectations with production ramping up faster than we expected when we first placed the refrigeration plant in service. Two, the decommissioning means of superior extraction efficiency of the cryogenic plant will now be realized sooner. And three, our midstream partnership with MarkWest is working well, allowing us to expand capacity faster and more efficiently than we could do on our own.

Another special time may be found embedded in the non-cash deferred tax line of the income statement. Because of our success in the Marcellus, we are projecting a shift in revenue from the Southwest states to the Appalachian states, particularly to the Commonwealth of Pennsylvania.

This projected change in income apportionment will only modestly increase our tax rate on an ongoing basis, but it does require us to reset our deferred tax provision on the balance sheet and run the change through the income statement in the fourth quarter. Result of this reset is a non-cash deferred tax expense totaling $16 million that reflects the sum of all projected future tax severances between the old estimated income apportionment and the new estimate.

We paid $354,000 in cash paid income taxes, and we received $1 million federal income tax refund in ’09. On an ongoing basis next year, our all-in tax rate is expected to be approximately 38%, with approximately $1 million of our tax liability payable in cash.

Year-end is when we update the estimate of our tax net operating loss carry-forward. And at December 31, ’09, our regular NOL carry-forward is $322 million, and our A&P NOL carry-forward is $259 million. These tax yields combined with approximately $526 million in previously capitalized intangible drilling cost deductions positioned Range well to manage through any potential changes in the tax curve.

Depletion, depreciation, and amortization during the fourth quarter was impacted by some of these unusual items, particularly the decommissioning of the refrigeration plant. This non-recurring charge combined with the 900,000 property impairment added $0.27 to the fourth quarter DD&A rate, which pushed the rate to $2.48 per Mcfe. The most important component of the DD&A rate, however, is our depletion rate. And depletion for the fourth quarter was $2.00 Mcfe compared to $2.05 last year and $2.25 last quarter.

The decline in depletion rate is significant for two reasons. One, the signals are improving drill bit capital efficiency, which is driving the rate down even while the rate is being pushed up by subtracting the low depletion rate legacy assets we’ve been selling. Two, depletion reduction, unlike most companies, has not caused by ceiling test write-downs of producing properties. The depletion rate should remain relatively constant next quarter, bringing the all-in recurring DD&A rate to approximately $2.25 per Mcfe.

As has been the case all year, our quarterly mark-to-market hedge accounting losses pushed us into a pretax loss position for the quarter just under $3 million. This quarter’s non-cash pretax derivative mark-to-market loss totaled $33 million. Because of the previously mentioned non-cash deferred tax apportionment true-up, the $3 million GAAP pretax loss turned into a $17 million after-tax net total loss.

The fourth quarter earnings calculated using the analyst consensus methodology was $52 million or $0.32 per fully diluted share. This is $0.05 higher than the analyst consensus estimate of $0.27. Please remember, the Range Resources website contains a full reconciliation of all non-GAAP measures mentioned on this call, including non-GAAP earnings, cash flow, EBITDAX and cash margins.

Before discussing recent additions to our hedging position and the condition of the year-end balance sheet, I’ll recap some key metrics for the 2009 fiscal year. Our own gas failed, including all derivative settlements for the full year of ’09 of just over $1 billion trailed the $1.2 billion of ’08. Our operating team held up their end of the bargain for the 13% year-over-year drill bit production increase despite significant asset sales. But with the oil and gas prices down 25% in ’09, the decline in revenue was inevitable.

EBITDAX for all of ’09 was $782 million, and cash flow for the year was $674 million. Cash flow per share for the year was $4.25, $0.12 higher than the analyst consensus estimate of $4.13. GAAP net loss for the year was $54 million, which included $118 million at pretax non-cash derivative mark-to-market losses. And adjusted earnings calculated using the analysts’ methodology for the year were $165 million or $1.04 per fully diluted share adjusted.

Range continues to build its hedge position in 2010 and 2011, with new collars added just over the past few months. We now have approximately 76% of our 2010 gas production hedged at a floor of $5.53 per Mmbtu and a cap of $7.23. We also have 20% of our oil hedged with collars at $75 by $93.75 per barrel. For 2011, we now have approximately 23% of our 2011 gas production hedged, with collars at $6 by $7.24 per Mmbtu.

As for our balance sheet, we spoke increasingly this year about our disciplined approach of capital spending and the improving capital and operating efficiency of our company. The year-end results verify that we have indeed walked the walk regarding these claims. First, we ended the year with $83 million less debt than we started despite posting 13% growth unaided by acquisitions, keeping our promise to live within cash flow and asset sale proceeds.

Second, we issued only a modest amount of equity to our employee benefit plans and several small transactions as currency for selected Marcellus acreage whose owners desire our stock. Third, we’ve reduced direct operating expense by 17% on an Mcfe basis, and even the 13% production growth we reduced 6% on an absolute dollar basis. Fourth, we’ve turned in company record low all-in finding and development costs, whether one uses the new SEC reserve rules or the old ones.

Fifth, thanks to our low cost structure, we incurred massive declines in oil and gas prices without the balance sheet being ravaged by ceiling test write-downs. And sixth, we’ve retained our 26-member bank group and $1.5 billion borrowing base through a tough bank market in significant asset sales, ending the year with almost $1 billion in available liquidity.

In summary, the financial view forward into 2010 is as promising as if you go backward into 2009, with our pending Ohio asset sale potentially pre-funding our anticipated capital spending gap and serving to further reduce our operating costs.

And John, I’ll turn it back to you.

John Pinkerton

Thanks, Roger. Good report. I’ll now turn the call over to Jeff Venture to review our operations. Jeff?

Jeff Ventura

Thanks, John. I’ll start the operations update with the Marcellus Shale. This time last year, our plan was to exit 2009 with net production from the Marcellus Shale from 80 million to 100 million cubic feet equivalent per day. We hit the high end of our guidance and we exited just over 100 million per day net. Today we are producing about 115 million per day net. We currently have 31 horizontal wells that have been drilled and are not yet online. Six of these wells have been completed and are waiting on hook-up and the remainder are waiting on completion. All of the wells will be completed within the next 90 days.

Our plan is to exit 2010 at a net rate of 182 million per day from the Marcellus Shale and to exit 2011 at a net rate of 360 million to 400 million per day. Give n our large acreage position and our net resource potential of 18 to 25 Bcfe, I believe that we can surpass 1 Bcf per day net production from the Marcellus Shale to grow towards 2 Bcf per day in the future.

In the Southwest part of the play, Range now has 40 horizontal wells with at least 120 days of production, with the oldest horizontal well having approximately 2.5 years of production history. We expect the average recovery of these wells to be 4.4 Bcfe gross. Zero time plot for these wells is on our website. We’ve also shown zero time plots for all of our horizontal wells by program year. It’s interesting to note that from 2007 to 2009, our effective horizontal lateral length has ranged from approximately 2,200 feet to 2,800 feet. And for the last two years, we’ve been averaging eight frac stages per well.

Beginning in August of 2009, we’ve began experimenting with longer laterals in additional frac stages. We now have drilled and completed 21 horizontal wells with lateral lengths of up to 4,100 feet and is frac-ed in with up to 14 stages. We have drilled an additional 10 wells with laterals ranging up to 5,000 feet and (inaudible) frac-ed in with up to 17 stages.

With the completions that we’ve run to date, I believe that the Marcellus has the best economics in any large scale repeatable claim in the US. This is in contrast to other shale plays where typically they took a long time in long laterals and lot of frac stages to make the economics of the other plays work. This speaks to the quality of the rock in the Marcellus.

However, as stronger the economics have been with Range’s wells in the Marcellus to date, we believe significant upside exists through longer laterals and additional frac stages. Typically longer laterals and additional frac stages would significantly improve the economics of the other shale plays such as the Fayetteville, Woodford and Bakken.

It’s interesting – or in addition to the great job the team has done in discovering, delineating and ramping up production in Southwest Pennsylvania, Range is now delineating and in the process of setting the stage for a ramp-up in the Northeast. Both of our first two horizontal wells in Lycoming County averaged about 13.5 million per day each, during a seven-day production test against simulated line pressure. Deep wells would be shut in and production will begin for Range later this year from Lycoming County.

Currently we are running 13 drilling rigs in the play. Plans are to add more rigs in the fourth quarter of 2010 and exit the year with approximately 16 rigs. During 2010, we expect to drill and case 150 horizontal Marcellus Shale wells. During 2011, we plan on increasing the rig count and exiting 2011 with approximately 24 drilling rigs.

We also drilled and completed our first horizontal Upper Devonian Shale well testing key shale intervals above the Marcellus. We are currently testing the well and initial results are encouraging. We’ve also drilled and cased our first Utica Shale well, which is below the Marcellus, and plan on fracking it in about a month. Early indications are encouraging as well.

The build-out of the Marcellus midstream infrastructure in the Southwest is progressing on schedule. Gross cryogenic processing capacity increased 155 million per day during the quarter, with startup of a new 120 million per day cryogenic plant at the MarkWest facility in Southwest Pennsylvania. And an additional 30 million per day of processing capacity is expected to be added in the third quarter of 2010 and another 150 million per day has been ordered for startup in the first quarter of 2011, increasing gross cryogenic processing capacity to 335 million per day.

In addition, we have tap capacity of 160 million per day of dry gas in the Southwest, with 20 million per day of gathering and compression capacity at this time. The gathering and compressing capacity will increase to 55 million per day by late 2011. Plans are to start dry gas production in Lycoming County late this year. Tap capacity in Lycoming County will be 350 million per day. Initial gathering and compression capacity will be 40 million per day, increasing to 120 million per day by late 2011.

In total, by year-end 2011, we will have gathering and compression capacity to cruise 400 million per day of gas in the Southwest and 120 million per day in the Northeast, for a grant total of 520 million per day. We plan to grow this with time as Range continues to develop its acreage position.

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, coal bed methane, tight gas sand and the Huron Shale. In the Huron Shale, we’ve now drilled and completed 23 horizontal wells throughout the field. Based on the performance of the wells, the vast majority of the acreage block appears to be prospective.

We’ve also drilled and completed four horizontal wells in the Berea sands, five horizontal wells in the Big Lime. In aggregate, we believe there is about 1.5 Tcf of resource potential in these horizons net to Range. All of this comes at three well F&D about $1.25 per Mcf at very low LOE about $0.60 per Mcf.

In addition, we still have over 3,000 coal bed methane wells to drill, including infill wells. F&D for these wells is less than $0.90 per Mcf. Today we are producing about 61 million per day net from Virginia and about 4 million per day from West Virginia. In the Barnett, although we’ve decreased our rig count from about six rigs at the beginning of 2009 to one currently, we grew production 25% year-over-year. In 2010, we plan on running one to two rigs.

Even at this stage, we expect the growth production 8% year-over-year and expect to average about 132 million per day for 2010. This is an excellent job by our Barnett team. The rates of return on the Barnett wells are still very good. Even at $5 gas, they are still 32%. We still have many locations to drill in the Barnett. But fortunately, we don’t have any significant drilling commitments. The bulk of our acreage is in the core of where many locations are largely held by production.

Let me now take a few minutes to discuss our 2010 budget. We plan to spend $950 million this year. 77% will be allocated to the Marcellus Shale division. This is a significant increase from last year when 52% was spent there. The increase is a direct result of the strong economics and growth of this project. It also reflects the fact that in the rest of the company we either own the minerals or the vast majority of our acreage is held by production. So we have the flexibility to throttle back spending there and focus our capital in the Marcellus.

The breakout of spending by division is 77% Marcellus, 11% Southwest, 7% Midcontinent, and 5% Appalachian. The Southwest Division is primarily Barnett drilling in the core part of the play, coupled with some strong oil deepening [ph] in Conger. The Midcontinent is primarily focused on the St. Louis, where early indications are the economics have the potential to rival that of any play.

The Appalachian drilling is on Nora. Of the $950 million budget, $700 million will be spent on drilling and $190 million on land. This is 96% of the total. The remaining 4% will be spent on seismic pipelines and facilities. So as good as Range has been in the past, we should be even better in the future. The F&D cost for all three major properties, the Marcellus, the Barnett Shale and Nora, ranges from about $1.00 to $1.50, and the LOEs for all three properties are very 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 a direct result of our simple strategy of strong organic growth at top quartile cost structure or better, and in addition, consistently building and migrating our inventory coupled with one of the 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 10-fold, primarily from the Marcellus Shale, more in 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 Pinkerton

Thanks, Jeff. Terrific report. Now let’s turn to 2010. Looking to 2010, it’s going to continue to be a challenging but also an exciting year for Range. Obviously the macroeconomic climate and the low commodity prices will be challenging, but we are extremely excited about the opportunities before us. Now, regarding Marcellus Shale, our goal in 2010 is continue to ramp up our drilling and double our production.

In 2010, we are planning to drill 150 horizontal wells and anticipating exiting the year at 180 [ph] to 200 million per day net. In addition, we focus on continuing to maximize our drilling returns, as Jeff mentioned, experimenting with our lateral lengths and the number of frac stages. The good news is that we are off to a great start. Again, as Jeff mentioned, the drilling results continue to exceed our expectations. Our first two horizontal wells in Northeast PA tested for over 13 million a day on a seven-day test. These are clearly outstanding results. And we are very excited about it.

In addition, while early, we are encouraged by the first Upper Devonian test and our first initial Utica test. In addition, the Marcellus infrastructure is proceeding as planned, as the cryogenic gas processing capacity is now at 155 million a day, heading into 335 million a day by early 2011. As Jeff again mentioned, on the dry gas side, we are making considerable progress on the infrastructure as well in terms of the dry gas side.

Regarding the Marcellus Shale play, we discovered what many believe is a giant natural gas field. When you look back in history, there are only a handful of companies of Range’s size that have discovered and developed fields at this potential magnitude. We’ve not only moved from the R&D side to the development side, we have captured a lot of the resource potential by aggregating a leasehold position of approximately 900,000 net acres in the fairway of the play.

Again, our acreage position in the outline of the play is materially higher than that, but we high graded to 900,000 net acres in what we consider to be the fairway or the core of the play. This is tremendous for Range and its shareholders to put the 900,000 net fairway acres in perspective. The three largest producers in the Barnett Shale play own in aggregate approximately 900,000 net acres in the high graded portion of the Barnett.

These three companies, Devon, XTO and Chesapeake, have a collective market cap of $73 billion. Given that the Barnett Shale play is the largest producing gas field in the US, this illustrates the opportunity we have before us. The important thing that all of our shareholders should focus on in particular is the per-share potential impact at the Marcellus Shale play can have on Range. This is why we say at Range we care about our stock price, not our market capitalization.

Now I want to turn to reserves for a moment. There had been much discussion regarding the new SEC rule for booking proved reserves. To provide a clear picture on the impact of the rule changes, we provided information to what our finding cost would have been under the old methodology. We also provided specific information as to how many Marcellus offset drilling locations we booked versus our producing well count.

We did this to continue our transparent approach and to indicate that we didn’t go out of our way to report all the Marcellus drilling locations we could have. Our goal is to consistently grow reserves over many years. Given this reasonable to conservative approach and our large resource potential, I’m confident we will be able to report low finding costs – finding and development costs not just for 2009, but for many years to come.

I’ll now provide some additional details on 2010. As mentioned in our release, our capital budget for 2010 is $950 million. Roughly 90% of the budget is attributable to the Barnett, Nora, and the Marcellus. We currently anticipate that 74% of the budget will be used to drill 338 net wells while the remaining $250 million will be used for acreage, seismic and pipeline infrastructure. We are targeting 12% production growth with this budget. The 2010 production growth target would have been 19% pro forma for the New York and Ohio asset sales.

Looking to 2011, we are looking at production growth in the 25% area. And again, as Jeff alluded to in his remarks, we continue to ramp up – we ramp up the Marcellus in all the core plays and anticipate that the rated growth will continue to accelerate. For the first quarter of 2010, we’re looking for production to come in at 460 million to 465 million a day. The midpoint represents 11% production growth versus the prior year quarter and its success will represent our 29th consecutive quarter of sequential production growth.

Roger discussed our outlook for the expense side of the income statement. In particular, I want to discuss lease operating costs. In 2008, our operating cost per Mcf averaged $0.99. In 2009, they dropped 17% to $0.82. In 2010, we are anticipating another 17% drop to $0.68. This reflects an impact of selling our higher cost properties and reinvesting the proceeds in the higher-return, lower-cost properties. As Roger pointed out, in 2009, despite increasing production by 13%, our operating cost per Mcfe declined by 17%. And as a result, our aggregate operating cost in 2009 actually decreased by over $18 million versus 2008.

Now, getting back to the capital budget, we set the budget at $950 million and, in fact, in an effort to keep spending in line with cash flow and asset sales. Given the high degree of operational control, we can and will remain flexible after the capital budget. The good news is that $5 flat NYMEX gas prices. Our drilling projects in the Marcellus, Nora and Barnett, all generate over 30% rate of return.

Currently we have natural gas hedges in place covering approximately 75% of our anticipated 2010 gas production at an average ore price of $5.50 per Mcfe, $0.50 higher than the $5 flat I just mentioned. As a result, having executed a definitive agreement on our Ohio property sale, which is expected to close by the end of March and given our 2010 hedge position, I feel very good about our 3010 capital program and our ability to fund it without taxing the balance sheet or diluting our shareholders with a material sale of equity.

Stepping back and looking at the big picture, assuming current futures market for the natural gas prices and our current capital outlook for the next three years, in 2010, 2011 and 2012, we are in aggregate approximately $1 billion short in terms of projected cash flow versus capital spending for the three-year period in aggregate. Because of the Ohio property sale, we reduced the shortage to slightly less than $700 million. We can easily fund the gap via additional modest asset sales and by modestly increasing debt in relation to stockholders’ equity as we book earnings over the next three years.

In late 2012, our projections indicate our capital program will be completely still funding to cash flow as company-wide production should be approaching roughly 1 Bcfe per day. The good news is that Range’s current shareholders should receive nearly all this benefit as it doesn’t look like we will need to issue any material amount of equity in the near future, except if we decide to undertake an accretive property acquisition.

Turning to our stock price for a moment, we are well aware that our stock price is at a high multiples of current cash flow and earnings. When a company the size of Range discovers a giant gas field, it appears to have some of the best economics of any field in North America. It makes sense that we should trade more on an NAV basis versus the current multiple of cash flow or earnings.

Over time, as we develop the Marcellus, our trading multiples and our NAV per share should move into parity. We have run many NAV models, and we believe that our NAV per share is substantially than our current stock price. As we and other operators de-risk Range’s 900,000 Marcellus fairway acreage position, our NAV will become increasingly clear to the market.

Let me make a simple NAV case for Range. If you take the $14,000 per net acre that Mitsui recently agreed to pay Anadarko for our third interest in Anadarko’s Marcellus acreage and plot that to our 900,000 net fairway acres, that equates to $12.6 billion. If you then value our – the proved reserves at the PV-10 value of $6.6 billion based on strip pricing asset close in our earnings release, you get $19.2 billion for both combined.

Given no value to Range’s other 1.6 million acres outside of the Marcellus fairway and subtract $1.7 billion of debt outstanding at year-end, you come up with well over $100 per share on a diluted share basis. While this is a fairly simple exercise and our NAV model is much more sophisticated, it illustrates the Range’s stock price has a long way to go.

Lastly, I want to take a moment to review the transformation of Range over the last several years and the impact that will have on capital efficiency and the value of our company. Since January 1, 2008 – since January 1 of 2008, we have sold our interest in the Fuhrman Mascho Field in West Texas, our New York properties, and we have a definitive agreement to sell our Ohio property. In aggregate, these three areas contain approximately 5,700 wells, and production per well averaged less than 10 Mcf per day per well. In aggregate, these properties represent roughly 50% of our well count, but only approximately 10% of our production and reserves.

As you can see, once we complete our Ohio sale in March, Range will be a much, much more efficient company with a much higher quality, low cost property base. We have begun to see the benefits of this transition to lower finding cost for 2009 as well as lower operating cost. This will allow us to do more with less. This will – we will be able to grow our production faster at lower cost. The bottom line, this will have a big positive impact on shareholder value per share.

Lastly, while we have accomplished much in 2009, I believe that the majority of our assets will benefit 2010 and beyond. As you heard from Jeff, we now have a projects that have 22 to 30 Tcf of net unrisked reserve potential. Finally, I would like to publicly congratulate and thank our talented team of roughly 850 employees for an extremely well – job well done in 2009. We have set the bar high for 2010, but I’m confident that was the talent, dedication and passion of the Range team we will meet or exceed our goals for the year.

With that, operator, that concludes our prepared remarks. Why don’t we turn the call over to question-and-answers?

Question-and-Answer Session

Operator

Thank you, Mr. Pinkerton. (Operator instructions) Our first question comes from the line of David Kistler with Simmons & Company. Please proceed with your question. Your mike is now live.

David Kistler – Simmons & Company

Hi, guys. Diving into the northeastern portion for a bit, I want to talk through development plans with the two recent horizontal well results. Little curious about how far apart those two wells were. And then you mentioned in your release pipelines tying in I think at the tail end of 2010 and also in 2011. And so I wanted to think about how rig count was directed there and the number of wells you might be tying in as the pipeline meets the project deadlines.

Jeff Ventura

Okay. This is Jeff Ventura. To answer your first question, the wells are approximately 9 miles apart. So they are good ways apart. And again, we’ve drilled other vertical wells in there. So I feel confident about the acreage and that we have really high quality acreage. Let me put a little color on it too. To keep the variables at a minimum back to the – we drilled a 2,500-foot lateral with eight stages. So it was more standard design. So I think you have the upside there with volume, with longer laterals and more stages and show improvement there. But I couldn’t be happier about our initial results. The pipeline will be there at the end of this year. So what you will see us do this year, of the roughly 150 wells that we will be drilling, 15 to 20 of those are going to be up in the Northeast. And what we will do is both delineate additional acreage, de-risk additional acreage, and have wells ready to tie in when the pipelines get there. You will see production really start right at the tail end of this year, and then you will see a significant ramp-up in drilling curve in 2011.

David Kistler – Simmons & Company

Okay. That’s helpful. Jumping over to Nora just for a second, you guys probably had a little less commentary on that, but I imagine experiencing the same sort of efficiency gains that you are seeing in days to drill and recoveries per well as you work through the typical learning curve. Can you give us an additional color around the economics of that play right now and potentially thoughts about increasing acreage position there?

Jeff Ventura

Yes. We talked a little bit about Nora itself. The results in Nora have been great. When we embarked on our strategy in the Huron Shale a year and a half ago, we just wanted to equally space wells across our roughly 300,000 acre position to understand the shale and its potential. And the good news, it looks like there is great potential really across the entire acreage position. The wells tend to – costs were coming down today. You are probably at $1.2 million per horizontal well, and I think that number will continue to come down. And reserves are roughly a Bcf for Huron Shale well. So that’s going great.

And then the other interesting thing, when you look at the other horizons, we’ve started to apply horizontal technology to the Big Lime and to the Berea and other horizons, and the economics look there is strong. We have a great acreage position. We are less than what we own the minerals there. So there is absolutely no pressure to drill. We will do it as it makes sense. And also there is really no need to expand. We think we’ve got tons of upside where we aren’t, but as usual, we will continue to look around and be opportunistic, but we will be very disciplined as well in terms of what we will do.

David Kistler – Simmons & Company

Great. Thank you guys very much.

Operator

Thank you. Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed with your question. Your mike is now live.

Ron Mills – Johnson Rice

Hey, guys. Jeff, you just mentioned a couple – answered a couple questions on the Lycoming wells in terms of lateral length and stages. Can you comment a little bit on the cost of those wells relative to Southwest PA and how that relates to guys like Cabot and Chesapeake have talked about as they move more to Susquehanna County, but talking more about 5-plus Bcf type wells?

Jeff Ventura

Yes. When you look at Lycoming County well we are drilling, and you’ve got to be careful when you are in the Northeast because you can find the Marcellus at a variety of depths, and if you go far enough east, it actually outcrops and is at the surface. Where we are in Lycoming County, it’s at about 8,500 feet deep. So the wells are going to cost a little more, roughly about $1 million more than our wells in the Southwest. In the development mode today, when we had drilling, our wells in the Southwest to drill and complete are about $3.5 million.

In a development mode in the Northeast, in Lycoming County where the wells are about 8,500 feet deep, I think you’re looking at $4.5 million. But couldn’t be happier, our first two tries out of the box, 13.5 million per day, and those are seven-day averages. And we’ll continue to test wells, and they look – they are going to be great wells. I can tell you that. So I think the reserves are going to be very strong. It’s a little early to pin down a number, but they are strong and they are going to be great.

Ron Mills – Johnson Rice

Okay. And then from – you obviously didn’t want to put out the 24-hour rates, but obviously much higher than that. Is there something going on in that – this is also one of those wells, I think located adjacent to where you drilled the vertical well, tested at 6.5 million a day. I’m trying to get a sense, as you move across your acreage position there, some of the attributes of the rocks that may cause those production rigs to differ, if any.

Jeff Ventura

Yes. One advantage that you have there, you’re deeper, you’re 8,500 feet and you have high pressure gradient. So you’ve got a lot of reservoir pressure, which is positive. You’ve got a lot of gas in place, and obviously you have some quality rock with this if you’re getting rates like that. The 24-hour rates were fantastic. We’re just putting out, we think, longer-term rates are still fantastic and they are probably more indicative of longer-term performance. But they are super wells. So I’m really excited about our position there.

John Pinkerton

Yes. And this is John. It’s important to note that the vertical well rate is plus 6 million a day. That was a 24-hour IP versus these are seven-day rates. And obviously our view is 24-hour rates (inaudible). That’s why hopefully as we go along here, we will give you more of these, like, seven-day rates and even longer rates, because I think those are much more indicative in terms of the quality of the wells versus given 24-hour IP. In some cases, that’s all you have. But in this case, we’ve tested these wells now and we had the seven-day number. So we decided those were more appropriate, more indicative of what we thought the well quality was versus giving you a 24-hour rate, which as you mentioned as probably a bit higher.

Jeff Ventura

And the other thing I’ll say is, like I said, we’ve actually given you guys the rates for all of our horizontal wells in the form of zero time plots, which I think are much better than type curve. That’s the actual real data by program year just put back the time zero. And the curve that we’ve put out is – and you can see the curves going up and down when you look at it by year. That’s just the actual real data. And then the sum of that data, we did smooth it, but it’s still a zero time plot, which I think is higher quality than a type curve.

Ron Mills – Johnson Rice

Okay. And then lastly, maybe this is for Rodney or Roger. With the sale of Ohio properties at the end of March, John, I guess you provided the first quarter production guidance, but with the impact of that sales, something where the second quarter will tend on an absolute basis to look more flat with the first quarter because of the timing of that sale and then their allocation or re-allocation of those sales proceeds would then drive more second half growth. Is that the right way to look at that 12% target?

John Pinkerton

Yes, that’s exactly the way to – and most likely, we will break our 29 consecutive quarter sequential production growth because we’re probably going to sell – close on the Ohio, say, right at the end of the first quarter. So we’ll have 25 million a day or so. It’s going to go flying off the production books. The good news is, as Jeff mentioned, we do have a number of plays that are in the process of being completed. And then we hook up whether we can overcome all 25 million of that in day one of the first quarter, first part of the second quarter. It’s going to be a real, real challenge for our operating team.

I wouldn’t bet against on it, but my gut feel is that we will see production either be flat or down a little bit in the second quarter, and then as we get the wells hooked and as these pipelines and whatnot, then you will see production really ramp up in the second half of the year on a relative basis for the first half. So again that’s – I think that makes absolute sense, and again it was part of the whole process we went through this year in terms of – if you think about what we’ve done last year, we sold Fuhrman right at about the middle of the year. This year we felt it is really important to really tee up the Ohio.

Really we teed it up at the end of – in the fourth quarter of 2009, really opened it up to data rooms in December. Chad and his team did a terrific job of getting all that organized and getting the data room open. And we had a lot of interest in those properties and we were able to come what we believe is a very good agreement with our friends at EnerVest in terms of VAT. And I think it’s a good deal for both sides. I think again it’s a really high quality property that had some upsides from some formations that they are focused on. Obviously we’re much more focused on the Marcellus over in PA. So it’s – I think it’s a win-win deal for each side. I think getting it done soon early in the year and getting it done in the first quarter is really important I think for us to be able to kind of charge-off on our capital program.

Ron Mills – Johnson Rice

And then the $950 million capital program, given your hedge position and the sales proceeds, is that based on a particular NYMEX price, somewhere in the low-to-mid sized, who were you continue to fund yourselves out of cash flow in the sales proceeds or how was that –?

John Pinkerton

Ron, given that we’ve got 75% of our gas production hedged at 5.50 floor, I mean, gas price could go to $4 and we’re still in good shape.

Ron Mills – Johnson Rice

Okay, great. Thank you.

Operator

Thank you. Our next question comes from the line of Marshall Carver with Capital One Southcoast. Please proceed with your question. Your mike is now live.

Marshall Carver – Capital One Southcoast

Yes. Of the 150 wells that you’re drilling and casing this year, how many do you plan on putting on line?

Jeff Ventura

About 90 of them.

Marshall Carver – Capital One Southcoast

Okay. And based on your commentary, I assume that’s more way towards the back half of the year.

Jeff Ventura

Yes, we’ll put them on as soon as we can, but the growth will be just like John described.

Marshall Carver – Capital One Southcoast

Okay, great. Cabot announced an impressive well in the Purcell Limestone earlier this week. Do you have a feel for how much of that could be on your acreage and do you plan on doing any test there?

Jeff Ventura

We have a lot of upside that’s very similar to that, but it isn’t the Purcell. It’s very analogous to the Purcell, and that the Purcell is a limy interval in the middle of the Marcellus. What we have in the Southwest, in particular, is we have the Tully, which is in between our Marcellus and the Upper Devonian shales that we have there. So we have a lot of gas in place to find because we’ve drilled through continually. We’re now just starting to test it. So we have a huge upside in terms of the Upper Devonian, and of course we are testing the Utica of the lowest.

I think more importantly, when you stand back and look at all that, what you’re really getting at is, I should say in my opinion, which is really important is, looking at gas in place throughout the trend and throughout the plays in the various horizons. You have to quantify where is that gas and plays located and looking what can the recovery be. We’ve told you that and particularly in the Marcellus acreage, we’ve got 18 to 25 Tcf of upside just from the Marcellus. I can tell you the upside from this Upper Devonian Shale and from the Utica is tremendous. And it’s literally on par with that. We haven’t put a number out yet. We’ve quantified it, we’ve been studying it for a long time, and we’re now testing it. But we’ve got tremendous upside in other horizons, and some of it is very analogous to what they have.

Marshall Carver – Capital One Southcoast

Okay, that’s helpful. And one last question, on the longer laterals, what’s the additional cost on those compared to the laterals – the average laterals that you’ve been drilling?

Jeff Ventura

The cost to drill the lateral is really inexpensive because the shale drill is really flat. It really comes down to how many additional pages are you pumping. So if you’re going to from eight stages to 16 stages or from eight to 12 or whatever that optimum ends up being.

Marshall Carver – Capital One Southcoast

But what was the total –?

Jeff Ventura

Just to put color on it, it may take a while that the development well in the Southwest from 3.5 million maybe to 4.0 million or 4.1 million. But again I think that if it’s worse, you’re going to be looking at better rates of return and actually lower finding cost.

Marshall Carver – Capital One Southcoast

Great. Okay, thank you very much.

Operator

Thank you. Our next question comes from the line of David Heikkinen with Tudor Pickering Holt. Please proceed with your question. Your mike is now live.

David Heikkinen – Tudor Pickering Holt

As you think about services cost and one of the things that we’ve heard on the live calls is increasing pressure pumping costs and kind of adding seven stages will affect your estimate kind of $85,000 a stage. Is it reasonable to think that those could escalate to 15% or 20% this year on a per-stage basis?

Jeff Ventura

That to me, it sounds a little high. I think you will see upward pressure. To me, it sounds a little high though based on what you’re saying.

David Heikkinen – Tudor Pickering Holt

Where would you expect the average stage cost to go?

Jeff Ventura

Maybe goes up 10% to 15% rather than 15% to 20%. And then now I think you’re going to have other things or it will be – a lot of our rigs are locked in and obviously those costs are flat fuel cost relative to last year, at least for the first half of the year probably will be relatively flat. So there is a variety of pieces in that total cost.

David Heikkinen – Tudor Pickering Holt

I’ll get right into the next question. As you think about rig contracts that you contracted as you’re growing into an increasing schedule, your ability to contract now is yet to be potentially at a little lower day rate. Is that sort of you see an offset to any increasing pressure pumping cost and a lower drilling cost?

Jeff Ventura

Yes.

David Heikkinen – Tudor Pickering Holt

Okay. That was – you walked right into that.

Jeff Ventura

That’s (inaudible). Even with the rigs we have, the costs are – I'm thrilled that we are at $3.5 million. Those new rigs, the efficiencies are so much greater that it’s a slight thing to do for us, and it will average out with time, it will help offset some of the costs like you’re saying.

John Pinkerton

Yes. David, as you know, I think one of the important things about the Marcellus, at least in the Southwest, is that when the rig rate (inaudible) in the Barnett, a lot of that equipment end up going to the Marcellus because it fit the Marcellus in terms of pressure pumping ability and size of rigs and whatnot. It wasn’t really able to migrate to the Haynesville because the Haynesville is obviously much deeper, a lot more pressure in terms of pressure pumping. So the good news is, in terms of I think in the piece of Barnett, there were 215 well rigs being in operation.

Today it’s probably way less than half of that. So there is still a lot of equipment, and I just think that the pressure in terms of that is going to be less than, let’s say, some of the other shale plays. That being said, at least in our view, there is probably a pretty good chance that the Marcellus by the end of this year will be the most active gas play in the world. So there is going to be pressure. The good news is, we’ve got great relationships with the vendors. We’ve been up there for a long time. We’ve got a lot of long-term contracts and relationships. And I think it would be crazy for most vendors know that we own 900,000 net acres in the fairway.

We own another several hundred thousand outside of the fairway that has the chance of being good. So I think our ability to attract high quality services – and it’s not just the equipment, the quality of people that work on that equipment as well. And the good news is that’s changing because a lot of people have moved up to Appalachia and being trained and whatnot. So we’re seeing a lot of progress in that area, and we’re very pleased. And again, it also has to do with the quality of our team.

We now have roughly 175 people in Pittsburgh. Two years ago, we had one. So we’ve really ramped up the team. We’ve got really high quality people. They have a lot of experience. And that’s what gives us the confidence that we can go from roughly 40 wells drilled and completed in 2009 to over about 150 for 2010. That’s a huge ramp-up in terms of activity. And again, you will see some of that in the back half of 2010, and you’re really going to see the ramp-up in the Boomerang in 2011.

That’s why we gave you that number, the corporate-wide number for 2011. So – and then it will continue to increase from that in terms of rate. So once we get through that and then obviously the key to life for all the shareholders, again, given that I’m the largest individual shareholder that we kick over in late 2012 in terms of being positive cash flow. And then at that point in time, it’s going to be (inaudible) in terms of what we’re going to be able to do. So pretty exciting – pretty exciting time in terms of all that.

David Heikkinen – Tudor Pickering Holt

Couple follow-ups to what you just said, John. As you look at the cash flow in that $1 billion and being part of the asset sales, what price deck are you using for that?

John Pinkerton

I use the strip, the gas strip on February – I think February 20th or something is what we used. I don’t have it right in front of me, but –

David Heikkinen – Tudor Pickering Holt

That’s fine, thanks. And then thinking about segregating activity levels as you ramped from 40 to 150 to 250 to 300 wells in 2011, how much will you do in the Southwest dry gas and then the wet gas, and then how much will you do in the Northeast region as you balance your program across the state?

John Pinkerton

We really haven’t – I mean, we have some ideas on that. I think Jeff gave you some pretty good numbers for 2010. I think it’s a little early to figure all that out obviously.

David Heikkinen – Tudor Pickering Holt

You’re obviously planning it just –

John Pinkerton

Yes, we are planning it. I think – I think at this point in time, we’re just not – we haven’t – we really haven’t got enough numbers on the paper. I feel comfortable to give those out in the public.

David Heikkinen – Tudor Pickering Holt

And then as you look at 900,000 acres and over 1 million acres, how does getting acreage or additional property acquisitions into that big inventory work? I mean, how do you think about that kind of big picture-wise as opportunities come up?

John Pinkerton

It’s obviously interesting, and it’s something that we spend a lot of time on. And let me just give you – it's really – David, that’s really a great, great question. Let me take just a little bit of time because I think it’s really important. If you think about it, we spent, I don’t know, $100 million this year on acreage. But our net acreage count in the fairway actually stayed even at about 900,000 acres. So yes, the question is, what did you do with that money? And what we did with that money is really block up our existing key areas.

We really think blocking up the acreage is the key to success in terms of being able to ramp up production at low cost, because if you think about it, if you block up your acreage and you can drill multiple wells from a well site. You’ve got one location, you’ve got one road, you’ve got one pipeline. You don’t have to – you don’t have pipelines all over the place and roads all over the place. It’s just much more efficient. It’s also much more environmentally friendly, and we’re being very sensitive to the citizens and the commonwealth in terms of doing that because we don’t want to tear up the surface.

So it’s a challenge. I think the good news is, is that we’ve been blocking up literally for about 2.5 years now. We haven’t bought any, what I’d call, trend acreage for over two, 2.5 years. In fact, we sold off what we considered to be some C-quality acreage in 2009. And we’re going to continue to do that, as time goes on. But I think you will see us do a number of things this year. We will continue to block up in and around our core areas. We will continue to do acreage trades. We’re trading acreage with other operators to block up.

And you’re also going to see us in some areas where we have, let’s say, scattered acreage or acreage that has – doesn't have as much term on as some others. You will see us actually contribute to those other operators and let them grow wells on our acreage where, let’s say, they have 60% and we have 40%. But it’s really high quality operator. We don’t have to operate everything, and we can leverage off of what they are doing. So I mean, we’re thinking through all of that stuff. All that being said, the one thing again in terms of doing a JV or selling off a big chunk of the acreage, we think the acreage is worth a hell of a lot more than the $14,000 that Mitsui paid.

And again, that is our opinion. We’ve run a lot of numbers. I mentioned when Chesapeake did the deal with the Norwegians, I thought the Norwegians got a pretty good deal. And I think the 14 – going 15,600 to 14,000. I think you will see that number continue to escalate up as more and more data gets out, more and more wells get out, and people get more and more uncomfortable with the economics of the Marcellus. So again, it’s a challenge, but I think we’ve got a good handle on it and we’ve got a lot of HBP acreage and obviously we’re HBP-ing a lot of acreages by our drilling plant as well.

David Heikkinen – Tudor Pickering Holt

Okay, thanks.

Operator

Thank you. Our next question comes from the line of Mike Scialla with Thomas Weisel Partners. Please proceed with your question. Your mike is now live.

Mike Scialla – Thomas Weisel Partners

Hi, guys. I guess, John, if somebody offers you $14,000 an acre tomorrow, you’re not a seller?

John Pinkerton

No.

Mike Scialla – Thomas Weisel Partners

Okay. In terms of some of the older wells in the Marcellus, do you see any changes in the liquid yields there? There has been some talk here recently about some of these (inaudible) areas, potentially rich for condensate type reservoirs. Have you seen any evidence of that with your area in the Marcellus?

John Pinkerton

No.

Mike Scialla – Thomas Weisel Partners

Good quick answers.

John Pinkerton

We are not seeing any changes –

Mike Scialla – Thomas Weisel Partners

In terms of the long-term plans for produced water, can you talk about those at all?

John Pinkerton

Yes. I’ve been really proud of our team up there. Not only we discovered the play in five years, in terms of the drilling and completion, but in terms of what to do with the water, really starting in about spring of last year, we started recycling water, and by August/September in the Southwest, where we’ve had drilling, we’re recycling 100% of our water. And that’s going really well. I told you the number other day. We’ve recycled over 70 million gallons of water, and the team has done a great job there. And so far, that looks great.

And the other thing we are doing is we are working with the authorities in terms of testing some disposals on and then setting up some water disposal wells. And the state liked – the DEP liked that solution, the EPA liked that solution, and we will be doing that this year as well. I think by the end of the year, and so far they are encouraging as well. By the end of the year, I’m hoping to couple recycling with the social wells, and if that works, those two things in common, I think that basically will take care of the water disposal problem. So basically in the pad [ph] drilling right now with recycling, we’re at zero discharge. It also reduces the need on the front end because you’re recycling on the water. And then to the extent you have step-out wells or extraneous wells, hopefully we will just go to our own disposal wells.

Mike Scialla – Thomas Weisel Partners

Okay. And Jeff, you said you are encouraged by the year-to-go. What you have seen there? Did you take course with schedule approach?

Jeff Ventura

What’s encouraging, I think, is a combination of two things. The answer is, no, we did not core. But clearly we ran extensive logs across including the (inaudible) logs where you’re coming with an estimate of how many Bcf per mount [ph] you have in place, and those numbers look very strong. Obviously you need to test to confirm it. As you’re drilling through it, you get gas shelves [ph]. There is different data that you gather. And so far, all of that looks encouraging. Obviously until you tested that the proof in the pudding. But so far it looks great, and we’re excited for the past.

Mike Scialla – Thomas Weisel Partners

Okay. And just one last one from me. John talked about blocking up your acreage, where does the state stand in terms of getting unit position or sometimes (inaudible)?

John Pinkerton

Yes, great question. We are – one of the real positives I think in the Marcellus is that there is a group of the industry, the E&P industry has formed a group called the Marcellus Shale coalition. And we hired a president of that, and this is real live organism that’s really doing good work, not only in terms of best practices across the play, which are in most cases much better and much higher stringent in terms of what the DEP is requesting, which I think I see that as a real positive. But some of the other things we’re doing is, as coalition come together to try to look at the current regulatory environment in some of the rules and regulations.

We’ve worked by to come up with proposals to the stake in terms of modernizing some of the rule sin there. And we’ve had very good dial log [ph], not only among the companies, but also among the regulators and the legislator that obviously to some degree ha a hand in that. So I see that all progressed very, very well, and I think you will see the fruits of all that hard work over the last year or so – we are at two years, come out later this year, with some hopefully some modernization signs that aren’t critical but that is important as the play ramps up in terms of just making everybody’s life easy, we’re also making it easier for the state, for the royalty owner, and for the companies that we maximize the place for all the different constituencies, which is really, really important. I think as we look out over the next five to 10 years in this play.

Mike Scialla – Thomas Weisel Partners

Great, thank you.

Operator

Thank you. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question. Your mike is now live.

Dan McSpirit – BMO Capital Markets

Gentlemen, good afternoon and thank you for taking my questions. Turning to the Northeast part of the Marcellus, 15 to 20 wells that you will drill there this year, what are the distances between wells and how much acreage do you think you will de-risk by drilling these wells?

Jeff Ventura

The distances between the wells will vary. Some of them are stepping out quite away, probably on the order of – when I said the 9 miles between the two wells, it’s actually 8.9 miles. To answer your question, I haven’t physically majored the ones that you’re probably looking at wells that are as far part as 20 or 30 miles. So they are pretty good plays. Other wells would be close and drilled to where the pipeline connections are. So the combination of wells and rates are stepping out. I think by the end of this year, through our drilling and through the industry drilling that a very significant portion of that acreage is going to be de-risk.

John Pinkerton

Let me just – this is John. Let me just take on what just Jeff said. One of the things, they give a little bit of what our plan was. Obviously we’re not a giant company with a giant budget. So we had to be very frugal in terms of how we ramped up and how we did that. That’s one of the reasons we picked this up. We’ll have to start. There is a whole bunch of technical reasons, but one of the business reasons was, we had pipelines in place. We already had field operations in Marcellus drilling. So there were a lot of reasons to start that. And now that’s up and gone, and we feel like we de-risk a whole boat load of acreage and we’re really excited about, and that’s what’s going to drive our production this year and have a big impact on the next several years.

The second stage of the next leg of stool is the Northeast. And one of the things that we’re really hoping that would happen that’s happened is that other companies would help de-risk our acreage. And that’s happening in a huge way. And we get calls all the time from companies and we share data and we share logs and test data and whatnot, and big companies, small companies, private companies, public companies. So the good news is a lot of wells have been drilled in the Northeast that’s really de-risking our acreage, without our capital dollars. And that was something that we hoped to happen and now it’s really happened, because the Northeast is really, really competitive. It’s really ramping up in terms of the number of rigs up there. And that really helps us. We’re all in favor of that. We’re a cheerleader on that side as we do that.

And then again, we will have a better idea how to develop our acreage from that. And then also the infrastructure will be easy. Now, the Southwest, we’re basically towing the road to us with our joint venture with MarkWest. Up in the Northeast, I think we will be more infrastructure joint ventures and thing with the other independents, so we’ll be able to share the cost and that freight going forward just because the acreage is – that’s the way the acreage is done. So again, both of time – so I think – stepping back, our grand vision is actually bearing the fruit pretty much like we thought and hoped it would. So all in all, we’ll – again, we’re pretty hectic.

Dan McSpirit – BMO Capital Markets

Okay, okay. And then turning to Texas Panhandle, the wells that you plan for 2010, can you talk about the objective there that you are drilling and the target of the economics?

Jeff Ventura

Yes. In the Texas Panhandle, specifically, we are targeting primarily the St. Louis formation. Our guys up there – we've got a pretty good acreage position already built, but we’re still leasing. So I don’t give a lot of details. But I will tell you the economics on it look really strong. You’re looking at cost to find and develop well below $1 and rates of return that are competitive with the Marcellus. So it’s – they have got a great play. Again, it’s something our team discovered and is leading the industry. And so that’s what we’re doing in the Panhandle.

Dan McSpirit – BMO Capital Markets

Okay. And then one more if I can. On both the Upper Devonian and the Utica tests, can you share any thoughts on maybe timing of results, expectations on economics and including costs?

Jeff Ventura

It’s probably for us going to be similar to what the Marcellus was a couple of years ago. Hopefully, and you’ve been looking and following us for a long time, and we continue to peel back the layers of the onion in the Marcellus and give more and more information. And in time we’ll be totally transparent with all of it. They are really spotting up our acreage and showing you the wells and help de-risking the whole thing. However, with the Upper Devonian and the Utica, sort of back where we were a few years back with the Marcellus. We think there is big upside and we want to make sure we capture that value for our shareholders. There is tremendous amounts of gas in place, and potentially large amounts in recoverable gas there. So we’ll be coy there, but in time again we will be putting up results.

Dan McSpirit – BMO Capital Markets

Very good. That’s all I have. Thank you again.

John Pinkerton

Thanks, Dan.

Operator

Thank you. We are nearing the end of today’s conference. We will go to Leo Mariani of RBC Capital Markets for our final question.

Leo Mariani – RBC Capital Markets

Hi, good afternoon here, guys.

John Pinkerton

Hi, Leo.

Leo Mariani – RBC Capital Markets

You guys talked about your retail being about 13 rigs right now in the Marcellus, going to 24 in 2011. Want to get a breakdown of how many of those are going to be spudded rigs versus horizontal rigs.

Jeff Ventura

Currently it’s about 50/50. I think that mix with time will just vary depending on how efficient the various rigs become. But right now, it’s about 50/50.

Leo Mariani – RBC Capital Markets

Hi. You guys plan on continuing to employ spudded rigs going forward, it sounds like.

Jeff Ventura

Yes. Where we are today, it looks like they drilled the vertical part in a more cost effective way and then we move off the air rig and come back, mud up, and bring in the bigger rigs. Today that gives us the best economic. And again, we can always try to improve with time, and we’ll see where that leads us.

Leo Mariani – RBC Capital Markets

Okay. I think you guys have made a comment on the call that a portion of your acreage a decent chunk in the Marcellus (inaudible) 900,000 is APP. Just curious if you guys could quantify a little.

John Pinkerton

It’s less than half, but it’s a big chunk

Jeff Ventura

Yes. With the drilling plans in place, we will be holding the acreage with time, and our team is very aware with that. And the drilling schedule that we put out accomplishes that for us.

Leo Mariani – RBC Capital Markets

Okay. And your position in Northeast Pennsylvania, I think about 350,000 acres, you drilled your first couple in Lycoming. What other counties in Northeast PA do you guys have significant acreages?

Jeff Ventura

We haven’t put out the specific counties, and again that’s jut for competitive reasons. We’re becoming more transparent. We told you where those really good vertical wells are and that’s where we drill our horizontals. But I’ll just say it’s a slot from Bradford, from Lycoming and a little bit through there. It’s right in the guts of where Mitsui just paid Anadarko $14,000 an acre for.

Leo Mariani – RBC Capital Markets

Okay. You talked about 4.4 Bs in Southwest PA I guess on the wells you drilled to date at this point in time being for your actual EUR. What’s your average lateral length over those particular wells?

Jeff Ventura

It’s probably going to be about 2,400, 2,500 feet. The low end is 2,200 feet. The high end is 2,800 feet. The low frac stages are three, although it was really in the first year. And there is – actually it’s on our website for the other years at seven or eight stages. And again, I think that’s fantastic results when you look at the economic that that generates, but I’m really excited about the experiment that we have in place. And that we will talk about over time. We just want to gather more production history, and what you will see us do is continue to update those plots and curves. And again, we’ve given you every single horizontal well we drilled in the form of a zero time plot, which is the just the actual data by program year. And we will continue to update that. Probably what we will do is break apart the shorter laterals that we drilled through August of last year and then this whole series of longer laterals and more stages. So we can quantify the difference.

Leo Mariani – RBC Capital Markets

All right. And I guess in your 2010 drilling program, is it going to be a majority of the wells that are going to have longer laterals at this point in time or is it more of a small fraction?

Jeff Ventura

Where we are today, the wells will be typically longer laterals than that and with more stages. What we don’t know at this point in time is where that optimum is, but we’ve got a lot of things in place and we will be defining that as we go forward. And of course, we will continually look and see we can improve there as we gather data. But we are setting them up for typically more than eight stages and more than 2,800-foot laterals.

Leo Mariani – RBC Capital Markets

All right. Thanks a lot, guys.

John Pinkerton

Thanks, Leo.

Jeff Ventura

Thanks, Leo.

Operator

Thank you. This concludes today’s question-and-answer session. I’d like to turn the call back over to Mr. Pinkerton for his concluding remarks.

John Pinkerton

Well, we’ve run quite a bit over. We really appreciate all of you who joined us today. Obviously we’re really excited about what we’ve got in the potential at Range. And we will continue to work hard and hopefully perform. And why don’t we just terminate the call? Thanks a lot.

Operator

Thank you for participating in today’s conference. You may disconnect your lines at this time, and we appreciate your participation.

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