山脈資源 (RRC) 2009 Q4 法說會逐字稿

Greetings, and welcome to the Range Resources 2009 earnings call.

(Operator Instructions).

Statements contained in this conference call, that are not historical fact are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question and answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Thank you, Mr. Waller, you may now begin.

Thank you, operator, and good afternoon and welcome. Range reported results for the calendar 2009 with record production, beating 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 seven years of quarterly sequential production growth with 2009's findings 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 target at an optimum cost structure on a per share basis to maximize shareholder values. I think will you hear those same themes reiterated from each of our speakers today. On the call with me are John Pinkerton, 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 would 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've posted on our website, supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, and the reconciliation of 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.

Second, we will be participating in several conferences in the coming weeks. Check our website for a complete listing for 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'll be attending the Simmons Energy Conference in Las Vegas, the JPMorgan High Yield Conference in Miami, the Thomas Weisel Partners Energy Conference in Denver, and we'll finish out 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.

Thanks, Rodney. Before Roger reviews the financial results, I will review some of the key accomplishments for 2009. Overall, we're 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 he a 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 and the -- 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 F&D costs averaged $1.00 an Mcf, the lowest in our history. Our drilling program alone delivered 400 -- I mean 540% reserve replacement at a cost of $0.69 per Mcfe. Again, the lowest in our history. Based on what we're seeing to date, these look to be some of the best results of our peer group. We combine excellent growth and 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 attributal directly to our very talented technical teams in our division.

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. And 2009 we completed $219 million of asset sales, over the last three years we've sold over $0.5 billion of properties. We believe periodically selling our more mature properties has several benefits. First, it helps focus us on our higher growth opportunities. Second, it provides additional capital for our high return activities. Third, it helps high grade our property base. And fourth, asset sales reduce the need to issue equity. From a financial perspective, we continued our disciplined and simple approach. Total debt declined by $83 million in 2009, and we ended the year with approximately a $1 billion dollars of liquidity under our bank lines. 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 the 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 high return projects like the Marcellus, Barnett and Nora Field. While not completely rule out Range doing a Marcellus JV. If we did want, we'd have to be at a substantially higher price than any previous deals including the recently announced Anadarko Mitsui joint venture. I want to keep all -- at the end of the day, I think it's our job to keep all Marcellus resource potential for Range's shareholders. In addition to diluting our NAV and resource potential for 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 a Marcellus well, we gain 85% of the production reserves and cash flow. By entering into a JV, our technical teams would have to drill significantly more wells to achieve the same net result. At Range, we prefer to keep things simple also, having a partner thousands of future Marcellus wells that we anticipate drilling over the next five to ten years will materially complicate our business and make us less efficient. With that, I'll turn the call over to Roger to discuss our financial results. Roger?

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 costs remains well below last year and our record drill bit growth did not come at 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 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 , a few cents 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 costs, on an absolute dollar basis, direct operating costs was almost $3 million less in the fourth quarter of this year than last year, even though production was 13% higher. Expect direct operating costs to hover around the $0.75 per Mcfe level for the fourth quarter -- for the first quarter of next year, until the impact of our pending asset sales take hold, after which direct operating costs 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 at just over $9 million compared to the $11.5 million last year. Exploration expense tends to be a bit front loaded in a new budget year, so looking ahead to the first quarter of 2010, exploration expense is like toll return to the $17 million to $19 million range. This is due to increased seismic purchases, delay rentals and exploratory drilling. General and administrative expense adjusted for noncash 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 costs associated with the pending sale of our Ohio shallow tight gas sand assets.

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 cent range 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 expense has drifted down, tracking the increase in production, with interest per Mcfe for the quarter of $0.73. It is worth noting that following the Ohio asset sales, 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 noncore 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 would like to explain some of the unusual income and expense items flowing through income statement. On the revenue side, we booked a $10.4 million gain on the cash sale of noncore undeveloped acreage in Pennsylvania, which is excluded from our non-GAAP adjusted earnings. This item helped to offset some of the noncash expense and impairment items, such as $10 million charge taken in connection with our soon to be decommissioned Marcellus refrigeration gas processing plant, a $900,000 proved property impairment on a producing field included in the Ohio asset sale package, and a $6 million noncash 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 has a silver lining, which is, we need the physical space, the refrigeration plant is sitting on to construct an expansion to our cryogenic processing capacity. The good news here is that, one, the Marcellus plays is exceeding our expectations with production ramping up faster than we expected, when we first placed the refrigeration plant into service. Two, the decommissioning means a superior extraction efficiency of the cryogenic plants will now be realized sooner. 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 item may be found embedded in the noncash 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 does it require to us reset our deferred tax provision on the balance sheet, and run the change through the income statement in the fourth quarter. The result of this reset is a noncash deferred tax expense totaling $16 million, that reflects the sum of all projected future tax differences between the old estimated income apportionment and the new estimates. We paid $364,000 in cash state income taxes, and we received a $1 million federal income tax in 2009. 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, 2009, our regular NOL carry forward is $322 million, and our AMT NOL carry forward is $259 million. These tax yields, combined with approximately $526 million in previously capitalized intangible drilling cost deductions, position Range well to manage through any potential changes in the tax code. Depletion, depreciation and amortization during the fourth quarter was impacted by some of these unusual items, particularly the de-commissioning of the refrigeration plant. This nonrecurring charge combined with the $900,000 property impairment added $0.27 cents 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 per Mcfe, compared to $2.05 last year, and $2.25 last quarter.

The declining depletion rate is significant for two reasons. One, it signals our improving drill bit capital efficiency which is driving down -- 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, the depletion reduction, unlike most company's, has not been 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 pre-tax book loss position for the quarter just under $3 million.

This quarter's noncash pre-tax derivative mark-to-market loss totaled $33 million. Because of the previously mentioned noncash deferred tax apportionment true-up, the $3 million GAAP pre-tax loss turned into a $17 million after-tax net quarterly loss. In fourth quarter earnings calculated using 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 the recent additions to our hedging position, and the condition of the year-end balance sheet, I will recap some key metrics for the 2009 fiscal year. Our oil and gas sales, including all derivative settlements for the full-year of 2009 of just over $1 billion, trailed the $1.2 billion of 2008. Our operating team held up there end of the bargain, with a 13% year-over-year drill bit production increase, despite significant asset sales. But with the oil and gas prices down 25% in 2009, a decline in revenue was inevitable. EBITDAX for all of 2009 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 analysts consensus estimate of $4.13. GAAP net loss for the year was $54 million which included $118 million of pretax noncash derivative mark-to-market losses. And adjusted earnings calculated using the analyst 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 with a floor of $5.53 per MMBtu and a cap of $7.23. We also have 20% of our oil hedged with collars at $75.00 by $93.75 per barrel. For 2011 we now have approximately 23% of our 2011 gas production hedged with collars at $6.00 by $7.24 per MMBtu. As for our balance sheet, we've spoken frequently this year about our disciplined approach to 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 live within cash flow and asset sale proceeds.

Second, we issued only a modest amount of equity through our employee benefit plans, and in several small transactions as currency for selected Marcellus acreage whose owners desire our stock. Third, we reduce direct operating expense by 17% on an Mcfe basis, and even with 13% production growth, we reduced it 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 endured massive declines in oil and gas prices, without the balance sheet being ravaged by ceiling test write-downs. And sixth, we retained our 26-member bank group and $1.5 billion borrowing base through a tough bank market and 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 the view backward into 2009, with our ending Ohio asset sale essential prefunding our anticipated capital spending gap, and serving to further reduce our operating costs. Now John, I will turn it back

Thanks, Roger. Good report. I will now turn the call over to Jeff Ventura to review our operations. Jeff?

Thanks, John. I will 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 to 100 million cubic feet equivalent per day. We hit the high end of our guidance, and we exited at just over 100 million per day net. Today we're producing about 115 million per day net. We currently have 31 horizontal wells that have been drilled, and are not yet on line. 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 180 to 200 million per day from the Marcellus shale, and to exit 2011 at a net rate of 360 to 400 million per day. Given our large acreage position and our net resource potential of 18 to 25 Tcfe, I believe we can surpass one Bcfe per day in net production from the Marcellus shale, and 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 two-and-a-half 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 2200 feet to 2800 feet. And for the last two years we've been averaging eight frac stages per well. Beginning in August 2009, we began experimenting with longer laterals and additional frac stages. We now have drilled and completed 21 horizontal wells with lateral lengths of up to 4100 feet, and have fraced them with up to 14 stages. We have drilled an additional ten wells, with laterals ranging up 5,000 feet and plans are to frac them with up to 17 stages.

With the completions that we've run to date, I believe that the Marcellus has the best economics of any large-scale repeatable play in the US. This is in contrast to other shale plays where typically they took a long time and long laterals and a 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 strong as the economics have been with Range's wells in the Marcellus to date, we believe significant upside exists through longer laterals and additional frac stage. Typically, longer laterals and additional frac stages have significantly improved 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 is in the process of setting the stage for our 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 testing against simulated line pressure. These wells will be shut- in, and production will begin for Range later this year from Lycoming County. Currently we're running 13 drilling rigs in the play. Plans are to add more rigs in the fourth quarter of 2010, and exit the year at 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 drill 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 have drilled and cased our first Utica shale well, which is below the Marcellus, and plan on fracing it in about 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 to 155 million per day during the fourth quarter, with start-up 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 2010, and another 150 million per day has been ordered for start-up in the first quarter of 2011, increasing gross cryogenic processing capacity to 335 million per day.

In addition, we have tap capacities 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 compression capacity will increase 65 million per day by late 2011. Plans are to start dry gas production in Lycoming County late this year. Tap capacity will be 350 million per day. Initial gathering and compression capacity will he be 40 million, increasing to 120 million per day by late 2011. In total, by year-end 2011, we'll have gathering and compression capacity to produce 400 million per day of gas in the southwest, and 120 million per day in the northeast, for a grand 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 will discuss Nora first. Successful drilling continues on all three horizons. Coal bed methane, tight gas plays, and the Huron shale. In the Huron shale, we now drilled and completed 23 horizontal wells through out the field. Based on the performance 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, and five horizontal wells in the Big Lime. In aggregate, we believe there's about 1.5 Tcf of resource potential in these three horizons net to Range. All of this comes with very low F&D, about a $1.25 per mcf, and 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're producing 61 million a day net from Virginia, and about 4 million a day from West Virginia.

In the Barnett, the although we've decreased our rig count from about six rigs at that time beginning of 2009 to one currently, we grew production to 25% year-over-year. In 2010, we plan on running one to two rigs. Anticipate at this pace, we expect to grow 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 $5.00 gas, they're 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 in the core, however, 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 Marcel less shale. This is a significant increase from last year, when 52% was spent there. The increase 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 focus our capital on the Marcellus.

The breakout of spending by division is 77% Marcellus, 11% Southwest, 7% Midcontinent, 5% Appalachia. The Southwest division is primarily Barnett drilling in the core part of the play, coupled with some strong oil (inaudible). The Midcontinent is primarily focused on St. Louis where early indications are the economics have the potential to rival that of any play. The Appalachian drilling is all in Nora. Of the $950 million budget, $700 million will be spent on drilling, $190 million on land. This is 96% of 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 costs for all three major properties, the Marcellus, Barnett shale and Nora, ranges from $1.00 to $1.50. And the LOEs for all three are very low. It's also important that two of our top three 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 high grading our inventory, coupled with one of the best teams in the industry. We believe Range today has more upside and more lower risk up side than at any time in the Company's history . With our inventory, we have the opportunity to grow the Company more than ten fold, primarily from the Marcellus shale, Nora and the Barnett shale. We believe our excellent organic growth, combined with an excellent cost structure will result in continuing to create strong shareholder returns over time. Back to

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're extremely excited about the opportunities before us. Regarding the Marcellus shale, our goal in 2010 is to continue to ramp up our drilling, and double our production. In 2010, we have planned to drill 150 horizontal wells, and anticipating exiting the year at 180 to 200 million per day net. In addition, we'll focus on continuing to maximize our drilling returns, as Jeff mentioned, experimenting with lateral lengths and a number of frac stages. The good news is that we're off to a great start.

Again, as Jeff mentioned, drilling results continue to exceed our expectations. Our first two horizontal wells in Northeast PA tested for over 13 million a day on the seven-day test. These are clearly outstanding results, and we're very excited about it. In addition, 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 it at 155 million, a day heading to 335 million a day by early 2011. And again, as Jeff mentioned on the dry gas side, we're making considerable progress ton infrastructure as well, in terms of the dry gas side. Regarding the Marcellus shale play, we've discovered what many believe is a giant natural gas field. When you look back in history, there are only a handful of company's of Range's size that have discovered and developed fields of this potential magnitude. We have not only moved from the R&D phase to the development phos, 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 and 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 an aggregate approximately 900,000 net acres in the high graded portion of the Barnett. These three companies, Devon, XTO, and Chesapeake have 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 that 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 have been much discussion regarding the new SEC rules for booking proved reserves. To provide a clear picture on the impact of the rule changes, we provided information as to what our finding costs would have been under the old methodology. We also provided specific information as to how many Marcellus offset drilling locations we've 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 record all the Marcellus drilling locations we could have. Our goal is to consistently grow reserves over many years. Given this reasonable to conservative approach in our large resource potential, I'm confident we'll be able to report low finding costs, and finding and development costs not just for 2009, but for many years to come.

I will now provide some additional details on 2010. As mentioned in our release our capital budget for 2010 is $950 million, roughly 90% of that budget is attributable to Barnett, Nora, and 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 at 2011, we're looking at production growth in the 25% area. And again, as Jeff alluded in to his remarks, we continue to ramp up, as we ramp up the Marcellus and our other core plays, we anticipate that the rate of growth will continue to accelerate. For the first quarter of 2010, we're looking for production to come in at 460 to 465 million a day. The midpoint represents 11% production growth versus the prior year quarter, and it's success will represent our 29th consecutive quarter of sequential production growth.

Roger discussed our outlook for the expense side of the income statement. And in particular I want to discuss lease operating costs in 2008, our operating costs per Mcf averaged $0.99. In 2009, they dropped 17% to $0.82. In 2010, we're anticipating another 17% drop to $0.68. This reflects the 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 costs per Mcfe declined by 17%. And as a result, our aggregate operating costs in 2009 actually decreased by over $18 million versus 2008. Getting back to the capital budget, we set the budget at $950 million in effect -- 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 as to the capital budget.

The good news is that at $5.00 flat NYMEX gas prices, our projects in the Marcellus, Nora, and Barnett all generate a 30% rate of return. Currently we have natural gas hedges in place covering approximately 75% of our anticipated 2010 gas production at an average floor price of $5.50 per Mcfe, $0.50 higher than the $5.00 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 2010 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 that time big picture, assuming current futures market for the natural gas prices, in our current capital outlook for the next three years being 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 programs will be completely self funding through 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 trades at a high multiples to current cash flow and earnings. When a Company the size of Range discovers a giant gas field, that 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 a current multiple of cash flow or earnings. Overtime, as we developed the Marcellus, our trading multiple 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 higher 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 a third interest in Anadarko's Marcellus acreage, and apply 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, you come one 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 that 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 -- yes, since January 1 of 2008 we have sold our interest in the Furnham-Mascho field in west Texas, our New York properties, and we have a definitive agreement to sell our Ohio properties. In aggregate, these three areas contain approximately 5700 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 through lower finding costs for 2009, as well as lower operating costs.

This will allow us to do more with less. This will -- we'll 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've accomplished much in 2009, I believe that the majority of our efforts will benefit 2010 and beyond. As you heard from Jeff, we now have 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 exceedingly well, job well done in 2009. We have set the bar high for 2010, but I'm confident that with 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 questions and answers.

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 mic is now live.

Hi, guys. Diving into the northeastern portion for a bit, I want to talk through development plans. With the two recent horizontal well results, a 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 wanted to think about how rig count was directed there, and the number of wells you might be tieing in as the pipeline meets the project deadlines?

This is Jeff Ventura. To answer your first question, while the wells are approximately nine miles apart, so they're a 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 2500-foot lateral with eight stages, so it was our standard design. So I think you have up side there with time, with longer laterals and more stages can show improvement there. But I couldn't be happier about our initial results. The pipeline will be there at the end of 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, derisk additional acreage, and have wells ready to tie in when the pipelines get there. You'll see production really start right at the tail end of this year, and then you'll see a significant ramp up in drilling occur

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

Let me talk 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, looks like there is great potential, really across the entire acreage position. The wells tend to -- costs are coming down. Today you're probably at $1.2 million for a horizontal well, and I think that number will continue to come down. And reserves are rough a Bcf for a Huron shale well.

So that's going great. And 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're blessed in that we own the minerals there, so there's absolutely no pressure to drill. We will do it as it makes sense. And also, there's really no need to expand. We think we've got tons of up side where we are. As usual, we'll continue to look around and be opportunistic, but we'll be very disciplined as well, in terms of what we'll do.

Great, thank you guys very much.

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

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

When you look at Lycoming County where we're drilling, and you've got to be careful when you're 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 where we are, is in Lycoming County, it's at 8500 feet deep, so the wells are going to cost a little more. Roughly about $1 million dollars more than our wells in the southwest. In the development mode today, when we are pad 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 8500 feet deep, I think you are looking at $4.5 million. But I 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've continued to test the wells, and they look -- they're 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're strong, and they're going to be great.

Okay. 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 area -- because this is also one of those wells was, I think located adjacent to where you drilled the vertical well that 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 rates to differ, if any.

One advantage that you have there, you're deeper, you are at 8500 feet, and you have a 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 it that you are getting rates like that. The 24-hour rates were fantastic. The longer term rates are still fantastic, and they're probably more indicative of longer term performance. They're super wells. So I'm real excited about our position there.

And Ron, this is John. It's important to note that the vertical well rate, of six million plus a day, that was a 24-hour IP versus these are seven-day rates. And obviously, our view is 24-hour IP rates that are -- can vary over the place. That's why hopefully, as we go along here, we'll give you more of these like seven-day rates, even longer rates, because I think those are much more indicative in terms of quality of the wells versus given 24-hour IP. But in some cases that's all you have. In this case we've tested these wells now for -- and we have the seven day numbers. So we decided those were more appropriate, more indicative of what we thought the well quality was versus giving you the 24-hour rate, which as you mentioned is quite a bit higher.

And the other thing I will 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 curves. That's the actual real data, by program year, just put back to time zero. And the curve that we put out, is that --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, but it's still a zero time plot, which I think is higher quality than a type curve.

Okay. And then lastly, maybe this is for Rodney or Roger, with the sale of the Ohio properties at the end of March. John, I guess you provided the first quarter production guidance, but with the impact of that sale, is it 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 the allocation, or reallocation of those sales proceeds would then drive more second-half growth? Is that the right way to look at that 12% target?

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 right at the end of the first quarter, so we'll have 25 million a day or so that's going to go flying off the production books. The good news is as Jeff mentioned, we do have a number of wells that are in the process of being completed, and then we hooked up. Whether we can overcome all 25 million of that in day one, the first quarter, first part of second quarter, is going to be a real, real challenge to our operating teams. I wouldn't bet against them, but my gut feel is that you will see production, either flat or down a little bit in the second quarter. And then as we get these wells hooked up, and as these pipelines and whatnot, then you'll 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 concern, and again, it was part of the whole process we went through in terms of, if you think about what we've done, last year we sold Furnham right at about the middle of the year. This year we felt really -- it was really important to really tee up the Ohio. So really, we teed it up at the end of -- at the fourth quarter of 2009, really opened it up to data room 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're able to come to what we believe is a very good agreement with our friends at Intervest, in terms of that. I think it's a good deal for both sides. I think they're getting some really high-quality properties, to have some up side from formations that they're focused on. Obviously, we're much more focused on the Marcellus over in PA. So I think it's a win-win deal for each side. But 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 charge off on our capital program.

And then the 950 million capital program, given your hedge position, and the sales proceeds, is that based on a particular NYMEX price, some where in the low to mid 5's to where you continue to fund yourself out of cash flow in the sales proceeds, or how is that designed?

Ron, given that we've got 75% of our gas production hedged at 550 floor, gas price could go to $4 and we're still in good shape.

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

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

About 90 of them.

Based on your commentary I assume that's more weighted towards the back half of the year.

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

Great. And 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 tests there?

We have a lot of up side that's very similar to that, but it isn't the Purcell. It's very analogous to the Purcell, in that the Purcell is a limey 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, that we've defined, because we've drilled through it continually. We're not just starting to test it. We have huge upside in terms of the upper Devonian. And of course, we are testing the Utica below it. I think more importantly, when you stand back and look at all that, what you're really getting at, or I should say in my opinion, what's really important, is looking at gas in place throughout the trend and throughout the plays, and the various horizons.

So you have to quantify where is that gas in place is located, and what can the recovery be. We've told you in that particular, in the Marcellus acreage, we've got 18 to 25 Tcf up of side just from the Marcellus. I can tell up the side from upper Devonian shales and the Utica shales is tremendous. 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 up side in other horizons, and some of it is very analogous to what they have.

That's helpful. One last question. On the longer laterals, what's the additional cost on those compared to the laterals, the average laterals that you have been drilling?

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

What would the total --

Well, to put color on it, it may take a well that's a -- development well in the southwest from $3.5 million, maybe to $4 million or $4.1 million. But again, I think that if it works, you are going to be looking at better rates of return, and actually lower finding costs.

Right. Okay. Thank you very much.

Thank you. Our next question comes from the line of David Heikkinen with Tudor Pickering Holt . Please proceed with your question, and your mic is

As you think about services costs, and one of the things we've heard on a lot of calls is increasing pressure pumping costs, and kind of adding seven stages, looks like you're estimating $85,000 a stage. Is it reasonable to think that those could escalate 15% to 20% this year on a per stage basis?

That to me, sounds a little high. I think you'll see upward pressure. To me it sounds a little high though, based on what you are saying.

What would you expect average stage cost to go?

Maybe it goes up 10% to 15% or something rather than 15 to 20.

Okay.

I think you that you are going to have other things that will be -- a lot of our rigs are locked in. Obviously, those costs are flat. Steel costs relative to last year, at least for the first half of the years, probably will be relatively flat. So there's a variety of pieces in that total cost.

You actually just fit right into the next question. As think about rig contracts, that you contracted as you're rolling into an increasing schedule, your ability to contract now, I would guess, would be potentially at a little lower day rate. That -- do you see an offset to any increasing pressure pumping costs and a lower drilling cost?

Yes.

Okay -- that was -- you walked right into that.

That being said -- even with the rigs we have, the costs are -- I'm thrilled that we're at $3.5 million. Those new rigs -- the efficiencies are so much greater. But it's the right thing to do for us, and it will average out with time, but it will help offset some of the costs like you were saying.

Dave, as you know, one of the important things about the Marcellus, at least in the southwest, is that when the rig rate tasked in the Barnett, a lot of that equipment ended 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 much deeper and a lot more pressure in terms of pressure pumping. So the good news is in terms of -- I think in the peak of the Barnett there were 215 wells -- rigs being in operation. Today it's probably way less than half of that.

So there's still a lot of equipment. I just think that the pressure in terms of that, is going to be less, let's say, than some of the other shale plays. That being said, at least in our view, there's 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's going to be -- 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 of -- most of the vendors know that we own 900,000 net acres in the fairway. And we own another several hundred thousand, quote, outside of the fairway, that has a chance of being good. So I think our ability to track high quality services, and it's not just the equipment.

It's 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've seen a lot of progress in that area and 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 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 about 150 for 2010. That's a huge ramp-up in terms of activity And again, you'll see some of that, in the back half of 2010. You're really going see the ramp up and the boomerang in 2011. That's why we gave that you that number, the corporate-wide number for 2011. So -- and 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, and again given that I'm the largest individual shareholder, is 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 Katy bar the door in terms of what we are going to be able to do. So pretty exciting, pretty exciting times in terms of all that.

A couple follow-ups, to what you just said, John. As you look at the cash flow, and that $1 billion dollars, and being able to fund it via the asset sales, what price deck are you using for that?

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

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

No, we really haven't -- we have some ideas on that. I think Jeff gave you some pretty good numbers for 2010. I think it's a little early yet to figure all that out.

You're obviously planning it?

Yes, we're planning it. I think at this . in time, we really haven't gotten enough numbers on the paper, I'd feel comfortable to giving those out in

And then as you look at 900,000 acres and over a million acres, how does fitting 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?

It's obviously interesting. And it's something that we spend a lot of time on. Let me just give you -- it's really -- David, that's really a great, great question. Let me just take a little bit of time, because I think it's really important. Is that, 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 you ask the question, what did you do with that money? And what we did with that money is really block up our existing -- our 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 got one road, you 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. We're being very sensitive to the citizens of 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, we've been blocking up literally for about two-and-a-half years now. We haven't bought any, what I would call trend acreage for over two, two-and-a-half 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'll see us do a number of things this year. We will continue to block up in and around our core areas. We'll continue to do acreage trades. We're trading acreage with other operators to block up.

You are also going to see us in some areas where we have, let's say scattered acreage or acreage that doesn't have as much term on it as some others. You'll see us actually contribute to those to other operators, and let them drill wells on our acreage where, let's say, they have 60%, we have 40%. If it's a really high quality operator, we don't have to operate everything. And we can leverage off what they're doing. All that being said, is 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's just our opinion. We have run a lot of numbers. I mentioned which Chesapeake did that deal with the Norwegians, I thought the Norwegians got a pretty good deal. And I think the 14 -- going 5600 to 14, I think you will see that number continue to escalate up, as more and more data gets out, and more and more wells get out, and people get more and more comfortable 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. Obviously we're HBP'ing a lot of acreage, as far as drilling plans as well.

Okay, thanks.

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

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

No.

Okay. In terms of some of the older wells in the Marcellus, you seen any changes in the liquid yields there? There's been some talk recently about some of these winter areas being potentially rich grade condensate type reservoirs. Have you seen any evidence of that with your area in the Marcellus?

No.

Those are good, quick answers. (Laughter.)

We are not seeing any changes, in terms of water. It is what it is.

In terms of the plants for produced water, can you talk about those at all?

I've been really proud of our team up there. Not only we discovered the play and pioneer it, in terms of the -- 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're pad drilling, we're recycling 100% of our water. And that's gone really well. I saw the number the other day. We have recycled over 70 million gallons of water. The team is doing a great job there. And so far, that looks great. The other thing we're doing, is we're working with the authorities in terms of testing some of the disposal zones, and setting up some water disposal wells.

And the state like that solution, the EPA likes that solution, and we'll be doing that this year as well. I think by end of the year, and so far early tests there are encouraging as well. By the end of the year, I'm hoping to couple recycling with disposal 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 drilling right now with recycling, we're at zero discharge. It also reduces the need on the front end, because you're recycling the water. And then to the extent you have step-out wells or extraneous wells, hopefully we'll just go to our own disposal wells.

Okay, and Jeff, you said you're encouraged by the Utica. What have you seen there, did you take cores? What's got you encouraged?

What's encouraging, I think, a combination of two things -- and the answer is, no, we did not core it. But, clearly we ran extensive logs across, including the infamous ECF logs where you are coming up with an estimate of how many Bcf per mount 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 shows. And there's different data that you gather. And so far all of that looks encouraging. Obviously, until you test it, that's the proof in the pudding. But so far it looks great. I'm real excited for the test.

Okay, and just one last one from me. John talked about blocking up your acreage. Where does the state stand in terms of getting unitization or some type of unitization law in place?

Great question. We are -- one of the real positives I think in the Marcellus, is there is a group of the industry, the E&P industry has formed a group called the Marcellus Shale Coalition. We've hired a president of that, and it's a real live organism that's doing great work, not only in terms of best practices across the play, in which most cases are much better and much higher, stringent in terms of what the DEP is requesting, which I see as a real positive. But some of the other things we are doing as a coalition, coming together to try to look at the current regulatory environment, and some of the rules and regulations we work by, to come up with proposals to the state, in terms of modernizing some of the rules in there. And we've had very good dialogue, not only among the companies, but also among the regulators, and the legislature that obviously to some degree has a hand in that.

So I see this all progressing very, very well. And I think you will see the fruits of all that hard work over the last year or so, really two years, come out later this year with hopefully some modernization things that aren't critical. But they're just important as the play ramps up, in terms of just making everybody's life easier, but also making it easier for the state, for the royalty owner and for the companies. So we maximize the play for all the different constituencies, which is really, really important I think as we look out over the next five to ten years in this play.

Great. Thank you.

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

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

The distances between the wells will vary. Some of them are stepping out quite aways -- quite a ways. Probably on the order, when I said the nine miles between the two wells, it actually 8.9 miles to. answer your question, I haven't physically measured the ones, but you're probably looking at wells as far apart as 20 or 30 miles. So they're pretty good plays. Other wells will be close, and drilled to where the pipeline connections are, so it will be a combination of building some rigs and 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 derisked.

Yes, let me just -- this is John. Let me just tag on to what Jeff said. One of the things that give you a little bit of where 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 that's one of the reasons we picked the southwest to start. There's a whole bunch of technical reasons, but one of the business reasons was, we had pipelines in place. We already had a field operation from our shallow drilling, so there was a lot of reasons to start that. And now that's up and going, and we feel like we've derisked a whole boat load of acreage, and we're really excited about it. That's what's going to drive our production this year, and have a big impact on the next several years. The second stage, or the next leg of the stool is the northeast. And one of the things that we're really hoping that would happen, has happened, is that other companies would help derisk our acreage. And that's happening in a huge way. 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. It's really derisking our acreage, without our capital dollars. That was something that we hoped to happen.

Now it's really happening, because the northeast is really, really competitive. It's really ramping up in terms of the number of rigs up there. And that only helps us. We're all in favor of. We're a cheerleader on that side as we do that. Then again, we can -- we'll have a better idea how to develop our acreage from that. Also, the infrastructure will be easy. In the southwest, we're basically towing a road to us with our joint venture with MarkWest. Up in the northeast, I think there will be more kind of infrastructure joint ventures, and things with the other independents. So we'll be able to share the costs, and that freight going forward just because the acreage, that's the way the acreage is done. So, again, both of them -- so I think stepping back, our grand vision is actually bearing fruit, pretty much like we thought and hoped it would. So, all in all, we're, again, we're pretty happy.

Okay. And then turning to Texas, the Texas panhandle, the wells that you plan for 2010, can you talk about the objective there that you're drilling and the targeted economics?

Yes. In the Texas panhandle specifically, we're 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 won't give you a lot of details. But I will tell you, the economics on it look very strong. You're looking at costs to find and develop well below a dollar, and rates of return that are competitive with the Marcellus. So it's -- they've got a great play. Again, it's something our team discovered, and is leading the industry. So that's what we're doing in the panhandle.

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

It's probably for us going to be similar to what the Marcellus was a couple years ago. Hopefully, and you've been following us for a long time, the and we continue to peel back the layers of the onion in the Marcellus and get more and more information. In time, we'll be totally transparent with all of it, literally spotting up our acreage and showing you the wells and how it's derisked, and the whole thing. However with the upper Devonian and the Utica, it's sort of back to 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's tremendous amounts of gas in place, and potentially large amounts of recoverable gas there, so we'll be coy there, but in time, again, we'll be putting out results.

Thank you again.

Thanks, Dan.

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.

Good afternoon here, guys.

Hi, Leo.

You guys talked about your rig count being about 13 rigs right now in the Marcellus, going to 24 in 2011. Wanted to get a break down how many of those are going to be spudded rigs versus horizontal rigs.

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.

All right, so you guys plan on continue to employ spudded rigs going forward, it sounds like.

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

Okay. I think you guys made a comment on the call that a portion of your acreage, a decent chunk in the Marcellus, like 900,000 is HBP. Just curious, if you guys could quantify that at all.

It's less than half, but it's a big chunk.

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

Okay. In your position northeast Pennsylvania, I think is about 350,000 acres. You drilled your first couple in Lycoming. What other counties in the northeast PA do you guys have significant acreage in?

We haven't put it specific counties. And again, that's just for competitive reasons. We are becoming more transparent. We told you where we drilled our two vertical wells are, and that's where we drilled our horizontals. But I will just say it's a swath from Bradford from Lycoming, a little bit through there, it's right in the guts of where Matsui paid Anadarko $14,000 an acre for.

Okay. You talked about I guess on the wells you've drilled to date at this point in time being sort of your actual EUR, what's your average lateral length over those particular wells?

It's probably going to be about 2400, 2500 feet. The low end is 2200 feet, the high end is 2800 feet. The low frac stages are three, although that was really in the first year. And there's actually, it's on our website, for the other years, seven or eight stages. Again, I think that's fantastic results when you look at the economics that that generates, but I'm really excited about the experiments that we have in place. And that we will talk about with 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've drilled in the form of a zero time plot, which is the actual data by program year. 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.

All right. I guess in your 2010 drilling program, is it going to be a majority of the wells that are going to have longer laterals, or is it just more a smaller fraction?

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'll be defining that as we go forward. Of course, we will continuously look at what we can improve there as we gather data, but we're setting them up, typically more than eight stages, and more than 2800-foot laterals.

All right. Thanks a lot, guys.

Thanks, Leo.

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

Well, we've run quite a bit over, and we really appreciate all the -- all of you that joined us today. Obviously, we're really excited about what we've got, and the potential at Range. And we'll continue to work hard and hopefully perform. And why don't we just terminate the call, have a lot better day. Thanks a lot.

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