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Range Resources (NYSE:RRC)

Q2 2011 Earnings Call

July 26, 2011 1:00 pm ET

Executives

Jeffrey Ventura - President, Chief Operating Officer and Director

Roger Manny - Chief Financial Officer and Executive Vice President

Rodney Waller - Senior Vice President and Assistant Secretary

John Pinkerton - Chairman, Chief Executive Officer and Member of Dividend Committee

Analysts

Brian Singer - Goldman Sachs Group Inc.

David Kistler - Simmons & Company International

Leo Mariani - RBC Capital Markets, LLC

Ronald Mills - Johnson Rice & Company, L.L.C.

David Tameron - Wells Fargo Securities, LLC

Gil Yang - BofA Merrill Lynch

Marshall Carver - Capital One Southcoast, Inc.

Operator

Greetings, and welcome to the Range Resources Second Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. This call may include forward-looking statements, which you may find more information about on our website at www.rangeresources.com.

It is now my pleasure to introduce your host, Rodney Waller, Senior Vice President for Range Resources. Thank you. Mr. Waller, you may begin.

Rodney Waller

Thank you, operator. Good morning, and welcome. Range reported outstanding results for the second quarter of 2011, with an increase in production in realized prices and a decrease in unit costs. As our operations continue to become more efficient, we're able to spend capital more efficiently and realize greater returns.

Range ended the quarter with the strongest balance sheet and the largest liquidity in its history. I think you'll hear these 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 with the SEC this morning. It's now available on the homepage 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 non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. We've also added tables which will guide you in forecasting our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also included on the website and will be updated periodically between quarters.

Second, we will be participating in several conferences in August. Check our website for a complete listing for the next several months. We'll be at Tuohy Brothers Energy Conference in New York on August 8; Tudor, Pickering Energy Conference on August 10 in Houston and the EnerCom Annual Oil and Gas Conference in Denver on August 15.

Now let me turn it over to John.

John Pinkerton

Thanks, Rodney. Before Roger reviews our second quarter financial results, I'll review the key accomplishments we achieved in the second quarter.

On a year-over-year basis, second quarter production rose 8%, exceeding the high end of our guidance. If you adjust for the Barnett sale, second quarter 2011 productions would have been 33% increase year-over-year.

Our drilling program was on schedule throughout the quarter as we drilled 91 wells. We continue to be extremely pleased with the drilling results. And despite the low natural gas prices, we're still generating very attractive rates of return. Currently, we have 21 rigs in operation.

The 8% increase in production was enhanced by our 14% increase in realized prices. As a result, second quarter oil and gas revenues were 23% higher than the prior year. The combination of higher prices and production combined with lower operating costs and unit costs, cash flow was 30% higher than the previous year.

Speaking of costs, we are most pleased on the cost performance side. On unit production basis, we saw a 9% decrease in our 5 largest cost categories combined. The only disappointment was that general and administrative expense came in at $0.59 per m, that's $0.07 higher than last year, due to higher legal fees and public relations expense. On the positive side, our DD&A expense and operating costs both continue to climb on a unit production basis, so we're very pleased with those.

With regards to our Marcellus Shale play, significant headway was made in the quarter, as we continued to drill fantastic wells, filling our acreage position and continue to build out our infrastructure. In addition, we continue to add high-quality technical personnel to our Marcellus team, which now includes approximately 400 people.

Lastly, we did all this while successfully closing the largest sale in our history with the Barnett sale. The sale allows us to aggressively pursue our other higher-return projects. The sale also puts us in the best financial position in our history, with nearly $290 million of cash on hand at quarter end, no outstandings on our $2 billion credit facility and no bond maturities until 2017.

All in all, I'm very pleased with what we accomplished in the second quarter. It's clearly a compliment, and a big shout out to the entire Range team for a job well done.

With that, let's turn the call over to Roger, to review our financial results.

Roger Manny

Thank you, John. With the Barnett sale closed at the end of April, the second quarter provides a good preview of what may be expected from Range, as it enters its post-Barnett era, namely, strong production growth, lower operating costs, plentiful liquidity and improved capital efficiency.

Before I delve into specific financial highlights, please remember that with the Barnett sale, we are again required to report our financial results using discontinued operations accounting. And we filed an 8-K that reflects our historical financial statements without the Barnett, and we've posted supplemental tables on our website and in the press release that reconcile the discontinued operations results with those in our 10-Q that include the Barnett.

Now because the second quarter included one month of Barnett asset ownership, the financial results I'll be presenting on this call, unless specifically noted, will include the historical results of the Barnett assets, which will then mask the supplemental non-GAAP figures in the press release.

Now since the balance sheet received continued attention in the second quarter, as we prepared the company for further expansion in our key plays, I thought we would begin our discussion there.

The first quarter saw the renewal and extension of our 5-year bank credit facility, with a higher commitment amount and borrowing base, lower interest rate and more flexible covenants. The second quarter of this year saw the closing and receipt of proceeds from the Barnett sale, the issuance of $500 million in fixed rate 5 3/4% 10-year senior subordinated notes and the full redemption of our $400 million and 6 3/8% and 7 1/2% notes that were due in 2015 and 2016.

Now that all the parts have stopped moving, the end result at 6/30/11 is a balance sheet holding $289 million in cash, a 57-basis point aggregate reduction to 6.85% in our long-term debt fixed interest rate, no long-term note maturities until 2017, an undrawn $2 billion bank credit facility borrowing base that has a $1.5 billion commitment amount and significant strengthening of our leverage ratios. As we continue to press on the development accelerator in our key plays, the balance sheet is well positioned to accommodate this activity.

Over on the income statement, there's more good news, starting with oil and gas revenue, including Barnett revenue and cash-settled derivatives of $266 million. This revenue figure is 23% higher than the second quarter of 2010. But just as significant, $266 million in second quarter revenue is only $2 million less than the first quarter this year, even though the second quarter includes just one month of Barnett results.

Cash flow for the second quarter was $168 million, 30% higher than the second quarter last year and slightly higher than the first quarter this year, making it the fourth consecutive quarter of improving cash flow despite the Barnett sale. Per-share cash flow for the quarter was $1.06, $0.07 above the analyst consensus estimate.

Second quarter EBITDAX was $201 million, 29% higher than last year and also increasing over the previous 4 quarters. Cash margin for the second quarter was $3.57 per mcfe, up $0.28 from the previous quarter and up $0.65 from last year's second quarter due to higher price realizations from higher liquids production.

Quarterly earnings calculated using analyst methodology for the second quarter, which excludes nonrecurring and noncash items, was $43.2 million or $0.27 per fully diluted share. That's $0.08 higher than the analyst consensus estimate, $0.19.

Year-to-date cash flow for the first 6 months of 2011 was $331 million, and year-to-date EBITDAX totals $399 million. As Rodney mentioned, please reference the Range Resources website for any questions concerning the reconciliation of these non-GAAP figures, including cash flow EBITDAX, cash margins and analyst earnings.

Moving down to the second quarter cost performance. There's more good news to report. The second quarter saw another drop in our DD&A rate from continuing operations from $2.08 per mcfe last year to $1.81 per mcfe in the second quarter. We anticipate that the DD&A rate in the third quarter will be approximately $1.79 per mcfe and will continue to decline further the rest of the year, providing tangible evidence of our steadily improving capital productivity.

Direct cash operating expense before noncash compensation but including workovers for the second quarter is $0.65 per mcfe. That's down $0.03 from the second quarter of last year, but more importantly, down $0.10 from the first quarter of this year. My compliments to the Range field operations team for all their hard work in getting us back on the path to lower unit operating costs.

Cash direct operating expense in the third quarter of this year is anticipated to be approximately $0.64 to $0.67 in mcfe. And we're still hopeful that we can push this unit cost down into the low $0.60 range by the fourth quarter, as our production volumes build and we drive more of our production from our lower cost producing regions.

Production taxes for the second quarter were $0.17 in mcfe. That's down $0.02 from last year. We expect production taxes to drop another $0.02 or so in the third quarter.

G&A expense adjusted for noncash stock compensation and other nonrecurring items, as John mentioned, was $0.59. That's $0.07 higher than the second quarter last year. G&A expense is sticking around that $0.60 level right now, and listeners can expect third quarter G&A expense to continue to be in the low $0.60 range before coming down a few cents more later this year, as production builds.

Interest expense for the second quarter was $0.76 per mcfe, that's slightly higher than last year, due to our issuance of additional long-term, fixed-rate notes and the negative interest carry incurred during the call period on the old notes that were not initially tendered. The $500 million, 5 3/4% note issuance, which replaced $400 million in higher cost debt also explains the one-time noncash $18.6 million loss on the early extinguishment of debt. As I mentioned earlier, the impact of the second quarter long-term note refinancing is significant, resulting in a 57-basis point reduction in the weighted average fixed interest rate on a $1.8 billion of long-term debt.

Extending these note maturities another 5 years also improves our future liquidity and lessens our interest rate exposure and refinancing risk. Looking toward the second half of this year, as we work off the remainder of the Barnett sale cash proceeds and our production volumes build, interest expense per mcfe will decline into the low $0.70 range.

Second quarter exploration expense, excluding noncash stock comp, was $11 million, that's $3 million below last year, due to lower delay rentals, offsetting higher seismic expense.

Now the timing of delayed rentals and seismic spending, like dry hole expense, is by nature, unpredictable from quarter-to-quarter. But based on our 2011 budget, we believe exploration expense could increase next quarter, back to the $24 million to $26 million range, depending upon the timing of these expenditures during the second half.

Abandonment and impairment of unproved properties came in at $19 million for the second quarter that was $900,000 wide of guidance. And the third quarter of 2011 should bring unproved leasehold impairments of $18 million to $20 million.

Range's federal income tax expense remains deferred in the second quarter, as our capital spending exceeds our cash flow, thereby generating excess intangible drilling cost reductions. So no Barnett sale proceeds will be lost to tax leakage, as we have ample NOL carryforwards and IDC deductions to offset the tax gain.

During the quarter, Range has continued to add to its hedge position. For the second half of 2011, we are 78% hedged at a floor price of $5 per MMBtu. For 2012, we have approximately 190 million cubic feet per day hedged with collars at a floor price of $5.04 and have recently added 70 million cubic feet per day hedged with swaps at $4.96, that gives us an effective floor price of $5.01 in MMBTu for 2012 on 260 million cubic feet per day of production. In 2013, we now have 160 million cubic feet per day hedged with collars at a price of $5.09 by $5.65 per MMBTu. Now that's up from 100 million cubic feet a day hedged at the end of last quarter.

We've maintained our favorable hedges on a portion of our 2011 and 2012 liquids production, with 7,000 barrels per day hedged in the third and fourth quarters of 2011 at $104.17 per barrel and 5,000 per day of 2012 liquids hedged at $102.59 a barrel. All of the hedge prices I just mentioned are net of any applicable premiums paid when establishing the positions. Additional hedging information may be obtained from the tables attached to the press release and also, the more detailed hedging tables Rodney mentioned that reside on our website.

As I mentioned in the start of my remarks, the second quarter of 2011 provides a glimpse into what our numbers are going to look like, following the Barnett sale. What you're going to see is strong production growth, greater capital productivity, low operating cost and a strong balance sheet from which to enter the next phase of our continued growth.

With that, back to you, John.

John Pinkerton

Thanks, Roger. Terrific update. Now let's turn the call over to Jeff to review our operations.

Jeffrey Ventura

Thanks, John. Range's net production from the Marcellus Shale is currently about 310 million cubic feet equivalent per day. Production performance from Range's wells in the Marcellus continues to improve. The average estimated ultimate recovery from 103 horizontal wells in the southwest portion of the play that were drilled and completed in 2009 and '10 averages 5.7 Bcfe. That's comprised of 4 Bcf of gas and 281,000 barrels of liquids. This has been a great accomplishment by our team.

After we drilled the industry's first successful well in the play and later offset it with successful horizontal wells, we estimated that the horizontal wells might be greater than 3 Bcfe per well. We later moved that estimate from a range of 3 to 4 Bcfe, then 3.5 to 4.5 Bcfe, then to 5 Bcfe per well. Now based on 103 wells from our last 2 complete years of drilling, the estimate has increased to 5.7 Bcfe. That's partly the result of our team going up the learning curve regarding how to better drill and complete the wells, and it’s partly due to the rock performing better than we expected.

It's important when comparing well results between areas and operators to factor in the completion. Range's 103 wells that averaged 5.7 Bcfe have an average lateral length of 2,802 feet with a non-stage frac. Other operators routinely drill longer laterals and pump more stages.

Based on a Goldman Sachs research report dated May 31, the average EUR for the 9 companies that they list is 5.7 Bcfe. However, many of those companies drill significantly longer laterals and pump more stages than Range, yet the average estimated ultimate recovery is the same. That implies that versus the average, the rock quality of what we're drilling is better. It also suggests that if we compete with more stages, we can increase the ultimate recovery of our wells. Of course, the key is to optimize the rate of return of the project not the EUR of a particular well.

Another key consideration is that we're still in the early stages of developing this play. Range, for 2011, mostly, is drilling 2,500 foot to 3,000 foot laterals with 8- or 9-stage fracs. With this design, we're generating 105% rate of return and $5 flat NYMEX. The 10-year NYMEX strip price currently averages about $6 per MMBTu.

Drilling and completing our wells in this fashion results in a development mode well cost of about $4 million. By keeping our cost down, we're able to drill more wells and hold more acreage and still generate an excellent rate of return. However, we have tested and are continuing to test alternative completions. To mention just a couple of the tests, we now have frac-ed a 3,950-foot lateral with 20 stages in Southwest Pennsylvania and are drilling a 4,500-foot lateral with 15 stages in Lycoming County.

Also at this point versus early on in the play, many companies are trying various lateral lengths and completions with lateral lengths up to 9,000 feet. Range will learn not only from our own tests, but we also closely watch the results of industry.

At this point, just in the southwest portion of the play, we have about 550,000 net acres. Based on about 1,000 industry wells drilled to date, 500,000 of Range's net acres have been de-risked. Assuming that 80% of the acreage will be drilled and as the development will be on 80 acres, we would then have 5,000 wells to be drilled in the southwest, considering only the Marcellus Shale.

Seeing that we've only drilled and completed a little over 200 horizontal wells, according to this math, we may have -- or we have 96% of our wells left to drill. As good as our rates of returns are now, we may be able to improve that going forward.

In the northeast portion of the play, we brought online our first 5 horizontal wells in the first quarter. The average estimated ultimate recovery for these 5 wells is 6 Bcf. The average lateral length of the wells is 2,573 feet with a 9-stage frac. For our first 5 wells, that's very encouraging. Again, like the southwest, we're running our own analysis of various lateral lengths and frac stages, and we'll also look at the results of other operators. Looking at the EUR on a per-stage basis, these are outstanding wells. As we bring on multiple wells during the remainder of the year, we plan to put together a type curve for these wells.

In the Upper Devonian, we'll be spudding our third well and its formation beginning in early 2011. This well will target the wet gas portion of the play and will be drilled into the area, with what we expect to be the highest gas and liquids content in place. In terms of liquids content, we expect the Upper Devonian will be like the Marcellus Shale, where the Marcellus is wet, the Upper Devonian should be wet. Where the Marcellus is dry, the Upper Devonian should be dry.

I also want to point out that the first 2 wells continue to perform very well. In the Utica Shale, we'll spud our second well early next year. The industry has drilled and will be drilling several Utica wells. Results of some of these wells will help to delineate Range's acreage. A lot of our acreage is perspective for both the Upper Devonian and Utica shale, along with the Marcellus. We hold all depth rights on our fairway acreage, so we will focus on driving up reserves and production in the low-risk, highly economic Marcellus play, which will hold the Upper Devonian and Utica potential both above and below the Marcellus. As we better understand the other 2 horizons with time, we'll then determine the optimum plan for each horizon.

Moving over to the Midcontinent division, I'll start with the discussion of our horizontal Mississippian play. To date, we have drilled and completed 7 horizontal wells, with an average lateral length of 2,197 feet with 12-frac stages. The average estimated ultimate recovery for these wells is 485,000 barrels of oil equivalent. At $100 per barrel flat NYMEX oil price, this generates about 100% rate of return.

Currently, we have over 45,000 net acres in this play, which equates to over 900 potential well locations. If we keep drilling with roughly 2,000 foot laterals, we believe that it will take 12 wells per section to develop the reserves, that equates to a little over 50-acre spacing. Assuming that the average recovery of 485,000 barrels of oil holds, that's a recovery factor of 4% to 9% of the oil in place.

Like my comments during the Marcellus talk, I believe that to compare the estimates of ultimate recovery per well between operators or between areas, you have to attempt to factor in the lateral length and frac stages to get a somewhat of an apples-to-apples comparison. We will observe how longer laterals are doing in other areas and what the costs are to drill and complete those types of jobs.

We'll also try different lateral lengths and different types of completions ourselves. We will be seeking the solution that generates the best project economics. If the optimum lateral length is longer, say, 4,000 feet instead of 2,000 feet, then the number of wells per section would most likely decrease from 12 to 6, and the spacing per well would increase from over 50 acres to over 100 acres per well.

Of course, the advantage to this play, like the Marcellus, is that there's a lot of hydrocarbon in place. Given the strong technical team that we have, coupled with the industry's track record of driving up recovery factor with time, I believe that is what we'll see happen here as well. Typically, the higher recovery factor comes from down spacing and better completions.

Up in the Texas Panhandle, we had excellent success with our first horizontal St. Louis well. It came online at 13.8 million per day and 903 barrels of liquids or about 19.2 million per day equivalent. After producing for about 7 months, it's still making 12.3 million per day and 760 barrels of liquids or 16.8 million cubic feet equivalent per day. Payout was within weeks. We'll be drilling 4 additional horizontal St. Louis wells this year.

At this point, I'll turn the call back over to John. I'll be happy to answer your questions in the Q&A.

John Pinkerton

Thanks, Jeff. Now let's look forward a bit. Looking to the second half of 2011, we see continued strong operating results. For the third quarter of 2011, we're looking for production to average 515 million to 520 million a day.

Factored into the third quarter production guidance is our Barnett sale. In the second quarter, the Barnett production was included for one month. For the third quarter, no Barnett production will be included. Assuming we hit the mid-range of our guidance for the third quarter, it will represent a 3% increase year-over-year. The 3% increase does not adjust for the Barnett sale. If you adjust for the Barnett sale, the year-over-year production growth would be 31%. We made up about half of the sold Barnett production by the end of the second quarter, and we expect to make up the other half by the end of the third quarter. So that's kind of exciting. We're right on track with that, and that's our business plan.

Now I'm going to talk a little bit about the fourth quarter. For the fourth quarter, we currently anticipate production to average between 606 million to 611 million a day. Assuming the midpoint, this equates to a 13% increase year-over-year, again including the Barnett. Adjusting for the Barnett sale, this equates to a 43% increase year-over-year.

Most of the fourth quarter production increase will come from wells that we've already drilled, and we're currently weighing pipeline connection. When you take this into account in the third -- in the fourth quarter production guidance, you can see we still expect to achieve 10% production growth, including the impact of the Barnett sale.

We also still expect to exit 2011 with the Marcellus shale production at 400 million a day net. Looking for -- looking at 2012, we're currently looking for production increase in the 25% to 30% range year-over-year and are still forecasting that we'll exit the Marcellus at 600 million a day or better on a net basis.

Now that we've closed the Barnett sale, I'll just take just a moment to look at the impact of our divestiture program. Including the Barnett sale, our divestiture efforts have yielded nearly 3 – pardon me, yielded nearly $2 billion in sales proceeds. It has also reduced our well count by approximately 6,000 wells. This represents about 60% of our well count.

The properties we sold were more mature, higher cost properties. The good news is that while we were selling our more mature properties, we were focusing our capital on higher-return projects. Despite the asset sales, our production and reserves had continued to increase. As a result, Range is now a more efficient company. We are doing more with less. By less, I mean, less wells, lower finding and development cost, lower operating costs, et cetera.

The second quarter results reflect a lower cost. In the third and fourth quarter results, you should see further progress in lowering our unit cost. Over the medium to long term, this will have a significant impact on our per share value. This is critical to generating attractive returns in a low gas price environment. In addition, by having fewer wells and properties and a more compact asset base, we can better focus our technical team on higher-return projects and make these projects better and better over time.

Lastly, one of Range's hallmarks is to keep things simple. By having fewer wells and fewer properties, Range is a simpler company, allowing the Range team to focus more of its efforts on driving up per-share value.

Besides the operating efficiencies, the Barnett sale was hugely important event for our company. First, the sales proceeds more -- were more than sufficient to retire all of our outstanding bank debt, with excess proceeds available to help fund our ongoing capital program. As a result, Range has, by far, the strongest balance sheet in its history.

Second, the proceeds generated by the sale are the catalyst for Range to become internally funded by the end of 2013. Obviously, natural gas prices will have a big impact on our ability to achieve this. And as you can see, we have put on additional natural gas hedges in 2012 and '13 to help us out in this area.

Since closing the sale, we have focused all of our energy on executing our business plan and driving up production reserves on a per-share basis with a top-quartile cost structure. The driver of this growth is our drilling inventory, which, I believe, is exceptional. We have the drilling results in place -- we have the drilling projects in play that at low natural gas prices, generate outstanding rates of return. As Jeff mentioned, our operating teams are continuing to enhance and improve our well results while maintaining our solid safety record.

While clearly biased, I'm convinced we have an exceptional asset base and drilling inventory, as well as an exceptional team of people driving our performance. Our management team is keenly focused on enhancing our asset base and improving our team's performance. Selling our Barnett property was somewhat of a bold move, as the Barnett property comprised approximately 20% of our production. However, we believe it best served Range shareholders, as it allows Range shareholders to retain 100% of our 35 to 52 Tcf of current resource potential.

Also, as I mentioned earlier, we currently anticipate 25% to 30% production growth in 2012, including the impact of the Barnett sale. From an investor's point of view, I believe Range is somewhat of a unique proposition. Because of our high-quality drilling inventory and low-cost structure, we can generate attractive returns at today's low natural gas prices. This provides substantial downside protection. On the other hand, because of the extraordinary resource potential at the Marcellus shale, in our other project, we have one of the largest per share upsides of any company in our peer group.

With the Barnett sale behind us, we are extremely excited and motivated. We appreciate the support and confidence of our shareholders that have shown -- that you've shown us. And we look toward, with great pleasure, to the second half of 2011.

With that, operator, why don't we turn the call open for questions?

Question-and-Answer Session

Operator

[Operator Instructions] Gentlemen, our first question is from Ron Mills with Johnson Rice & Company.

Ronald Mills - Johnson Rice & Company, L.L.C.

Question on the Mississippian, Jeff. You started talking about the lateral links. I know in your first 7 wells the 2,200-foot lateral's lower than what other operators have been testing, which is roughly double that, yet your recoverabilities in terms of EURs are about the same. What's driving the performance in terms of EURs versus a lower -- a shorter lateral length? And what does that presage if you drill longer laterals, in your opinion?

Jeffrey Ventura

That's a great question. I think, I said a similar type thing in the Marcellus. If you look at our average complete -- if you look at the average recovery per the Goldman Sachs report, Range is right in the middle of the pack, yet our wells are significantly -- have significantly fewer stages and shorter laterals. Sort of implies that we have higher-quality rock at where we are. And plus it says, we may have upside in terms of well recovery can continue to go up if we decide to move those completions up. And I think the same thing would be true in the horizontal Mississippian play to get a similar recovery from a shorter lateral might imply higher quality rock or higher oil cup. So that would say that there could be upside in terms of if we change our completion design. That being said, I'd like to reemphasize that what we're currently doing in both plays generates greater return, greater than 100%. So I think the good news though is that there's upside beyond where we are today.

Ronald Mills - Johnson Rice & Company, L.L.C.

Great. And then a follow-up, just in terms of planned activity, you've drilled 7 wells. How much activity do you think you’ll have over the second half of the year in terms of rig count or well count? And then, are you also staying ahead of the game in terms of saltwater disposal systems to handle the wells once they're ready to be completed?

Jeffrey Ventura

Yes, let me answer -- let me do it in the order that you said. For the second half of the year, we have no drilling activity planned there, and we're currently putting together, and we will be putting together, now and through the fall, our budget and capital spending plans for 2012. It's very early but, I believe what you'll see, subject to board approval is we'll start program drilling early next year in the Mississippian, where we have at least one rig, and we'll be looking up and we'll pick up the second rig and so on. So you'll start to see program drilling next year. The good news is if you only roll back and answer that question about the saltwater disposal in a 2- or 3-minute answer, if you look at what we did up in that area, we really started there a few years ago. And we started there, and we got into the area, because we thought it was a good stacked-pay area, and we had a really strong technical team, which is sort of the types of things that we look for strategically within the company. So stack-pay area, literally from almost 700 feet down to TD, which there is literally 6,000 feet or a little shallower. Great stack-payer, you have probably more than 20 productive horizons. So we started developing some of the shallow horizons 4 or 5 years ago, in really the Tonkawa section out there, the Tonkawa sands. And with that, we put in our water disposal systems and everything. Probably, about 2 to 3 years ago we shot a 3D over that big field and started drilling deeper targets in the Mississippian and then in the Wilcox, all with good success and continued to expand out to water disposal. And then we moved off structure and started drilling the Mississippian off structure with good success. And then start -- and these were all vertical wells. And then we started, last year, drilling horizontal Mississippian wells, again with good success, 7 wells averaging 485,000 barrels of oil equivalent. And then it's a very liquids-rich area. So we have our water disposal system in there, and we will stay ahead of that. And the good news there is you got a great disposal zone directly below you in the Mississippian and the Arbuckle, very prolific water disposal zones. So I think we're in great shape, strong team. We're building a really exciting acreage position, and you'll see us start continuing drilling, I believe, next year.

Ronald Mills - Johnson Rice & Company, L.L.C.

And lastly, just to expand on that last comment, the acreage position has gone from 15,000 to 28,000 to 45,000 acres. And given your size and scale, the question -- last question just on scalability of this play, which has continued to grow in aerial extent and by the higher profile that you're placing on this, is this a scenario that you would look to expend incremental capital?

Jeffrey Ventura

Yes, we're very judiciously picking up additional acreage, and really, today, our acreage position's probably a little above that. And we're, really, probably approaching about 1,000 potential locations, assuming it all continues to drill out. If you take 1,000 locations and -- it's very early, but those 7 wells average 485,000 barrels of oil equivalent. 1,000 locations if it worked out times 485,000 barrels. That's 485 million barrels of oil. And then when you net that back, just on the acreage position we have really, in hand, we're about close to 400 million barrels net. That's impactful. I think our team is -- we're continuing to acquire additional acreage, and I think we can build that. So can we build 1,000 maybe in the 1,500 locations and beyond? So 400 million barrels might become 600 million barrels and beyond. And we're acquiring that in a very disciplined fashion, in a blocky position, where we've got good infrastructure. So I'm excited about the team there and the play that we have.

Operator

Our next question comes from the line of David Kistler with Simmons & Company.

David Kistler - Simmons & Company International

On a little bit bigger picture basis, if we reflect on BHP's bid for Petrohawk, where they're certainly putting or willing to pay for resource potential above and beyond proved and kind of look towards your position in the Marcellus. And it’s definitely focused on kind of the Utica and Upper Devonian, where you've done a little testing but not a lot. Given the strong financial position, do you think about accelerating testing there, basically, to prove up resource potential in an effort for a marketplace that might have more consolidation?

Jeffrey Ventura

Well, let me start out by talking a little bit just about potential, and then I'll turn it over to John to speak to the more global issue. One of the things I want to say, I mentioned in my notes, and we have just a couple of Upper Devonian wells that we’ve tested. But every single Marcellus well that we drill goes through the Upper Devonian. So we have well logs and shells, and in some cases, whole cores or sidewalk cores on those intervals. And a lot of it looks prospective for our southwest portion of the acreage. And just like the Marcellus, a lot of it's wet. So when we talk about having on the order of 500 million barrels net to us of NGLs in the Marcellus with the position we have, leaving the ethanes in the gas, we have a big upside in terms of Upper Devonian. We did drill and complete a couple of wells. I mentioned they’re performing well. And I talked about them on the last call, so you can go back and look at it. But we talked about just a couple of wells, so it's not a valid sample, but we have a lot of data. We've mapped it. And you look at the -- last time, I mentioned a better well looked like it might be on the order of 3.5 Bcf. Since then, the wells producing -- the decline curve really has flattened. And when we look at the reserve estimates today, that initial well looks like it might be a 4.7 B, which is really exciting, considering we only drilled and completed 2. So there's a lot of upside in terms of how we can drill and target, and we'll consider that. The other thing I want to point out, in terms of the Upper Devonian and some of our, really, Marcellus acreage, where we’ve targeted the first Upper -- 2 Upper Devonian wells. The first well, we just targeted away from the Marcellus wells to make sure that we had a good clean test. The other one was sort of off of a pad, where we had a lot of wells, and we were wanting to make totally sure the gas was coming from the Upper Devonian. We had a lot of control. We didn't sit back and target, where is the thickest, best, wettest portion of the play. Our next well's going to do just that. So we really haven't even targeted, from a technical point of view, where the best area should be, plus you got to factor in the whole completion size, length, how do you land it, all that type of thing. So I think there's a lot of upside in the Upper Devonian. Same thing would be true, some of our Marcellus, only just roll back there a little bit, but it's important, I think, in the global question that you ask. Since Ranger -- when we pioneered -- the plant started, we picked Washington County to drill it. And we had good success, so we continued to drill around there. And then when we drilled up in Lycoming County, where we started recently, same thing. We didn't target our biggest, thickest, best portion of the play. There, we started drilling where there was a pipeline connection. So off of our first few wells, we're getting wells that look like off of 9-stage fracs. It could be 6 Bs. I mean, you could proportionately say, what if those were 18-stage fracs or 16-stage fracs, what would the recovery factor be for those wells? And then you got to factor in that we haven't drilled the highest gas in place, biggest, thickest, portion yet. Same is even true of some of the stuff in the southwest. So I think there's a lot of upside, technically, to our position. And the Utica is a bigger wildcard, because it's below both of those horizons, not a lot of tests in them. But our first well, which I believe was the industry's first horizontal, was clearly encouraging. There's a lot of rumors, and I'm sure everybody on the call has heard them in terms of other Utica wells. And I'm sure you're going to hear some outstanding Utica wells between now and the end of the year. And a lot of our acreage looks prospective for the Utica as well. For the Marcellus and for the Upper Devonian, we have big portions of the wet gas, along with some dry gas in the Utica, were primarily all, for the most part, dry gas. With that, I'll turn it over to John.

John Pinkerton

Yes. I mean, I obviously second what Jeff said. I think, in terms of the -- in specific, Dave, you asked about the BHP-Petrohawk deal. I mean, I think the key takeaway for me on that was, one hail to Floyd Wilson. So I'm going to send Floyd a nice bottle of wine here. But in reality, kidding aside, I think, what it tells you is, is that NAV really matters. And at the end of the day, the companies that can drive up their NAV on a most cost-efficient basis, on a per-share basis, are the ones who are going to be the big winners. And that's all we're focused on. And we’ve found a giant gas field. We're going, I think, relatively fast. In fact, I think even some of those bigger companies, at least in the short term will actually go slower but -- until they get their feet on the ground. But we're going relatively fast. I think, as Jeff mentioned, the good news is there's going to be lots of other Upper Devonian and Utica wells drilled by other people that'll help develop the industry's perception. And of these other plays, just like in the Marcellus, we were the first ones to kind of jump up out of the bunker, running up the hill. And then over time, our friends at Cabot and all the other companies started drilling really good wells. And that's really good for us, because it helps: one, it helps the play in general; and two, it really helps acreage that we have in and around a lot of these other operators. I mean, damn, we own a whole lot of acreage. So when other people drill around us, it really helps us. And we're trading logs between companies now and trading data. So all that's happening, and that's all really good for Range and its shareholders. And again, I think at the end of the day, we're really focused on driving up NAV per share. We understand that all of this has a time horizon. But again, you just look back and you look in some of our presentation materials, and you look at the production curve of the Marcellus 3 years ago, we were at 20 million a day, then 100 million, then 200 million, then 400 million, and 600 million. And you start -- you continue that up, and then you add these other formations on, and then you add the Upper Devonian. I mean, you add some of the other projects we're doing in other areas. You can really see, I think, a pretty dramatic increase in terms of production and at low cost. And I think that'll continue to transfer into an NAV number. Obviously, we've got one, it's dramatically higher than we think the stock price is today. I mean, in multiples of where the stock price is today. But it's up to us to prove it, and that's what we're into. And we want to do it on a per-share basis. That's why we sold the Barnett, because we were confident we could take the money, recycle it and still have good growth for 2010 and then -- I mean, 2011 and outstanding growth for 2012, '13, '14 and '15. But it's up to us to prove it. And that's what we're doing right now -- is trying to prove it. And hopefully, over time, as we prove it, the market will give us credit. But we don't expect the credit until we prove it, and that's what we're all about.

David Kistler - Simmons & Company International

Great. I appreciate that. And maybe just as a follow-up in terms of you highlighting the purpose to drive NAV going forward. If we think about what you guys have said in the past where your 2012 CapEx budgets being much like 2011, yet coming into today, balance sheet's a lot better, credit facility certainly provides plenty of room to outspend cash flow, returns out of the Marcellus, they're better, efficiencies are getting better, offsetting service costs. Should we be thinking 2012 CapEx goes higher as a way to accelerate the increased NAV?

John Pinkerton

David, that's a really good question, and that's something that Jeff and I and Roger and some of the other guys, when we go out to lunch, we talk about a lot, thinking through. I think we're just now starting to kind of tinker around and look at 2012. Obviously, we’ve got a long-range plan that's got some fences around it. But in terms of the specifics, we're now -- we're just starting to tinker with that. And Jeff and I were just talking about it this morning, in fact. And one, it's pretty exciting, and we've got a lot of opportunity. And it's good to see our costs coming down, because that allows us to do more. But yes, I mean, we expect to generate great growth for 2012. But we're going to be opportunity-driven. And to the extent that the Mississippian or St. Louis plays has those opportunities, we're going to do the best we can to fund those things, to capture those things for our shareholders. So right now, I think it's just a little early. We need to get our numbers finalized. We need to get to our board, which we'll do later in the year. But no, we're going to -- one of the great things that we've done, as you mentioned, is we have great balance sheet. And so it's great to have a great balance sheet. Every once a while, you need to use it, which is what Roger always says. Now Roger's going to be -- make sure that Jeff and I don't go off the reservation but -- so we got a great balance sheet, to the extent that the Mississippian turns out great or the St. Louis. We'll have the -- we have the dry powder to exploit those things and take advantage of them. And again, that's a great place to be, and that's one of the things that we were hopeful would happen with the sale of the Barnett. And the good news is that it happened. We closed the Barnett. We've made up -- really, we've made up about over 60% of production, and we'll have the rest of it made up by the end of this -- the third quarter. So I guess, this -- it clearly puts us on the offensive. And that's really exciting and I think, for our operating teams, it's exciting, and some of the opportunities we see. And quite frankly, there's other things that we're working on, kind of grassroots things that we're working on that we haven't discussed. But some of those even look pretty exciting, and obviously, they're small and they’re not going to take much capital, more thoughts and ideas and a little bit of acreage and a few wells here and there. But I can assure you, we've got a great inventory. I can't be more excited about where the company is today and the future that holds for the company than any time in my measly 22 years since I've been President or CEO of the company. So it's just an incredibly exciting time at Range. And you can really see it around the office and the employees and whether it's Pittsburgh or Oklahoma City or Abingdon, Virginia or West Texas, some of the projects we have out there. They're really excited to be at Range right now.

Operator

Our next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Could you -- John, you said that -- you highlighted again, I think, you said in the first quarter that in the fourth quarter, a lot of the growth was going to come from the backlog of wells that you will complete. Can you just review for us what that backlog is currently, where you think it could be at the end of the year? And what parts of the Marcellus as well as are …

Jeffrey Ventura

Yes, Gil, this is Jeff Ventura. Let me jump in with that question. When you look at the northeast, we put 5 wells on in the first quarter. We recently brought on 5 more. We have 27 more coming on by the end of November, so that'll be 37 wells up there. And then we talked about 21 wells awaiting connection in the southwest and 51 awaiting completion. Of the 21 awaiting connection, we'll put 14 of those on in the third quarter and one in the fourth. And of the 51, while waiting completion, there are probably 90% of those will be on or 80% to 90% by the end of the year. And that's where the growth -- a lot of the growth that John's talked about is going to come from.

Gil Yang - BofA Merrill Lynch

Okay. Great. You made a comment that the 2009, 2010 program is 5.7 Bcf. If you look at the presentation -- your presentation, your 2011 wells are tracking a little under that. Is there anything going on that -- or you’re doing in this areas? Are you doing shorter laterals? Or are you doing anything peculiar?

Jeffrey Ventura

Yes. Gil, if you actually look at that, it's actually the 2011 wells are higher. They're not lower. If you look on the -- Rodney has the curve, right here. If you look at the 2011 wells -- maybe you're talking about we're early on, on the IP, that's just a function of some constraints and all gathering. But the overall quality of the wells looks good and really is on par, if not, a tick higher when you look at the -- each individual well, individually, and project the math.

Gil Yang - BofA Merrill Lynch

Yes. I'm just looking at the aggregate data that you showed in your presentation.

Jeffrey Ventura

Yes, yes, yes. That's just a function of some constraints early on, sort of like that Upper Devonian well that I mentioned. Early on, on that Upper Devonian, we talked about the first well. Now I'm saying, it looks like it might be 4.7 B that came on under constraint conditions of 2.5 million per day, 1.9 million gas and 91 barrels of liquids you have to have a 4.7 Bcf well. So ultimately at the end of the day, we think it's about rate of return, not about IP. It's the full shape of the curve. Looking at the individual well data that we're looking at, we're excited about our 2011 program.

Gil Yang - BofA Merrill Lynch

Right. And it sounds like the 2011 program, you're basically tracking the lateral length and other stages of the previous 2 years of [indiscernible], right?

Jeffrey Ventura

Yes, that's correct. It's on par, it's very similar. But like I said, we put a number of experiments out there. We frac the well that just probably about a month ago in the southwest that had 20 stages in it. So we're looking at some of those types of things.

Operator

Our next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Following up on your comments on the Upper Devonian what is the thickness and thickness variability that you're seeing there that you expect versus the Marcellus? And what are you thinking about rates of return from drilling a shale or Upper Devonian zone versus what you're seeing in the deeper Marcellus?

Jeffrey Ventura

Well, when you look at it, it's a combination and not just thickness. But at the end of the day, it comes down, I believe, to hydrocarbon in place and how much of it can you get out. The Upper Devonian section relative to the -- and really where it's -- we feel it's -- the highest prospectivity is in the southwest, although there's a couple of good Upper Devonian wells, even in the central part of the State, so it has potential in a lot of areas. When you look at the thickest part of the Upper Devonian, in general, say, in the southwest -- it's actually on our website, you can look at it, there's a type log. The section in aggregate is thicker than the Marcellus is but the Marcellus is more organic. When you look at gas in place, it ends up actually being about equal. So where we've got 80 to 120 Bcf a section in the Marcellus, the Upper Devonian is about the same. So basically, you could pick the midpoint. Say it’s 100 Bs a section in the Marcellus. The Upper Devonian doubles that to 200 Bs a section. And to go the other way, it's interesting, the Utica in a lot of cases is a little bit more than that. It's probably like down in that same area, maybe 120 to 140 B, so it can be an aggregate in over 300 Bs per section. And the exciting part is that it's predominantly stacked in the southwest. Specifically, though, going back to the Upper Devonian, I think, 2 wells are just too early. It's really exciting though that on our second well it looks like 4.7 Bs as of today. And every time we look at it, the decline gets a little flatter. What we haven't done is targeted the highest gas in place interval or the highest in -- like I was saying earlier, ends up actually with the hydrocarbon in place is actually in the wet part in the Upper Devonian down there. So we'll be spudding a well right on that bull's eye, but it's a big bull's eye in a big area. The section itself is literally right on top of the Marcellus. So even though it's a little bit shallower, the well costs in reality are going to be pretty much the same. But the exciting part is we'll have an infrastructure in there. We have a team there, and you're going to have roads and well pads and gathering and takeaways, so there's really an exciting upside to it.

John Pinkerton

Brian, this is John. When -- if you just go and drill your Upper Devonian wells on the same pad site, where you drilled your Marcellus well, when you take into account the road, the pad sites, the gathering systems, if you look at all the costs there, you've already spent -- you already got -- you can cheat off somewhere 25% to 30% of your well costs have already been expended by the Marcellus wells that you've already drilled. So it really, it kind of turbocharges your Upper Devonian returns, if you drill on top, but on the same pad sites where you’ve already drilled your Marcellus wells.

Brian Singer - Goldman Sachs Group Inc.

Got it. That's helpful. Going to the Marcellus, you highlighted the higher IPs. One of the reasons for that was better-than-expected rock performance. Are you seeing that in the form of just better IP rates or lower declines? And are you seeing that more in the first-year decline rate or in more of the longer and medium-term decline rate?

Jeffrey Ventura

Let me better define that. If you look at those curves, in general, every year, we're progressing upward when you look at -- from when we started until now. But it's not just IPs, it’s flatter declines and therefore, higher ultimate recoveries. So what I'm saying when we’re looking at moving the ultimate recovery from 3 to 4 to 5, now it looks like for the last 2 full program years 5.7. I'm saying that in aggregate is a combination of better completion, but a big part of it is just flatter declines.

Brian Singer - Goldman Sachs Group Inc.

And is that flatter decline happening in the long-term decline rate, or is it more your wells you thought would decline at a bigger first-year rate and they’re not declining at that rate, they’re declining at a lower rate?

Jeffrey Ventura

I think it's a combination of that. It's a combination of both. It's that whole curve has probably shifted to a shallower decline.

Brian Singer - Goldman Sachs Group Inc.

Okay. Great. And lastly, can you just refresh us on how much further down you think your OpCosts can go, as you ramp up the Marcellus, and as we see more NGLs coming on does that lead to any uptick in costs, in addition to the uptick in realizations?

Jeffrey Ventura

I mean, when you look at -- the nice part about where we're, at least, for this year, we're putting 86% of our capital into the Marcellus and historic. So one, if you look at the Marcellus wells, they're high rate flowing gas wells. So they're pretty inexpensive to operate initially. And then like John mentioned, we've divested a couple of billion dollars worth of properties, a lot of those in general were higher-cost properties, higher LOEs. So by not drilling in those areas and selling them, coupled by focusing our capital in our highest rate of return, low LOE area, we'll continue drive them down. As far as specific guidance, I don't know. Roger, I think, talked about where we expect to be in fourth quarter. And we haven't given guidance, I don't think beyond that yet.

Roger Manny

Yes, Brian. Low 60s, I think, we feel real good about. I mean, getting something with a 5-handle's going to take a lot more work, but we'll see what 2012 holds for us.

John Pinkerton

This is John. I'll be a little bolder here. Yes, I can do that, I guess. I think Brian, great -- I've got great confidence in our team. And one of the things -- if you think about the fourth quarter, we're going from 515 to 520 in the third quarter. And we're going to 606 to 611 in the fourth quarter. If you think about that, a lot of those -- a lot of that production increase is coming from wells we've already drilled and completed -- in most cases completed, and we’re waiting on pipeline. I mean, it's going to take some more people to operate those wells, but it's not going to be the same, because a lot of the people operate those wells and in those areas, we've already hired and trained and everything else. So I'm really looking to the fourth quarter with a lot of excitement to see where those costs come down. And I don't want to set a bar that drives Roger and Jeff crazy, but I think that's going to be a great snapshot, in terms of the capital efficiency not only on the drilling side, but also on the operating side, as we turn those wells on, and you get that production increase in the fourth quarter. So I think that's going to be a good data point in terms of that whole -- where we can take this thing. But I'm going to be -- -- I'm cautiously optimistic. I think the guys will hit the ball out of the park. But again, we'll stick with Roger's numbers, and then hopefully, we'll over-perform and make everybody happy, including me.

Operator

Our next question comes from the line of Leo Mariani with RBC Capital Markets.

Leo Mariani - RBC Capital Markets, LLC

Just wanted to jump into Northeast Pennsylvania a little bit more. I guess, talked about 6 Bcf EUR. Just curious as to where the well costs are up there right now?

Jeffrey Ventura

Yes. Well, let me start with the southwest, and I'll move up there. We said in the development mode in the southwest would be at $4 million. And actually, I'm glad you brought it up, because one of the questions somebody asked earlier today was, where are you today? And when you look at today, off the AFPs that are coming in the Southwest, a lot of the wells are 4 million to 4.2 million. I've seen some straight away wells as low as 3.8. We just got one and some lighter swing outs, 4.4. But a lot of the wells are just a tick over 4 million. So the team's done a excellent job of driving down costs in the development mode. And remembering, we started a lot higher like you typically do. In the northeast ultimately, if we’re at 4 million in the southwest, we'll put some economics and stuff out later on. And in development mode, those wells might be 5.2 million, something like that. And we're probably 200,000 to 400,000 over that for the wells today. But the guys are making great progress quicker, and we're climbing that curve there even quicker than I thought. I still think -- and those are the numbers, I said 3 years ago when we started into the play, and if you go back to -- Ray Walker's in here, and he's looking at me. And Mark Whitley’s just left the room -- and you go back to some of those early wells in the Southwest, our first 3 horizontals in 2006. We never really said what they were, but they were fairly ugly. You were looking at wells of 6 million. And I said, ultimately, I believe, the team could get them to 4 million in development mode. Well, we're only 200 wells in. We got 96% of the wells left to drill, and that's probably a conservative number. At 96% left to drill, and yet we're almost right there in the Southwest. And I still think there's a lot of upside if we kept that same completion design, and we're -- in terms of where that team, John Applegath [ph] and team can drive those numbers to, Don Robinson and the other guys. If you go up to the Northeast, I thought it would take us a lot longer to get to where we are. But they're early wells up there. Remembering, you're a couple thousand feet deeper than in the southwest. Lycoming County is one of the deeper parts of the play. They're making a ton of headway early. And Mark Whitley told me recently that he thinks development mode is comfortable with 5.2 million. That's Mike Middlebrook's division now. David, Don and the guys working on that with the right ground staff, I'm sure they can get those numbers there quickly. And I think in time, we'll surpass them. Like I said, if we're already in a development mode, 4% of the wells in, I think there's a lot of upside in terms of what that team can do.

Leo Mariani - RBC Capital Markets, LLC

Great. I guess, just switching gears a little bit over to the Mississippian. You guys clearly picked up more acreage. You got just over 45,000 net acres there now. Just curious as to how much of that you think is de-risked by your drilling as well as industry? And if you can kind of on a ballpark there?

Jeffrey Ventura

Yes, it's really interesting. We've had really good success drilling in that area for a few years in multiple horizons including verticals. We drilled a lot of verticals into the section so we have good control. Our horizontals, I think, if you look at the 2 farthest wells apart, they're on the order of 7 miles. But when you really come up to a 50,000-foot level and look at the play, we're having a really good success where we are. If you go off to the west, SandRidge and Chesapeake a long ways away, and a whole way from where we are, they have wells close to us that goes a long ways out. We're having good success, and if you go off to the east, there's some smaller independents that are having good success as well. So I think it's an exciting play. It's a big oilfield. And we've got a good position and it's growing. So I think it's so far so good. Oh, well cost? We're at -- right now, we're around -- we said we'd drill complete costs of $2.9 million, and we allocated a couple hundred thousand of saltwater disposal well to that to account for. We just allocated our saltwater disposal well back on a per-well basis. We're close to that now. We're not too far away from that. And we really haven't put together, hey, if we have literally 1,000 wells to drill, where do we think we'll be on well 100 or 150. But again, we've got a great team up there led by Max Holloway and Bill Coger [ph] and got a great drilling group working for them. I'm sure there will be good things there as well, with time.

Leo Mariani - RBC Capital Markets, LLC

Got it. I guess, last quick question for you guys. You talk about potentially accelerating this play in 2012. I guess, you got a couple other wells you're going to drill in the St. Louis line. That looks to me to be your best rate of return well at this point in time? I think, Jeff, you said it’s paid out in a number of weeks. I guess, you got other locations there. I mean, I guess, that would seem to be another play that given the quick payout you would think you could accelerate that potentially. Can you guys comment on that and maybe what you think your inventory might be in the St. Louis line?

Jeffrey Ventura

Yes. We'll drill 4 more St. Louis wells there this year. We just drilled and set pipe on the first one. In fact, today, we started completion on it. When you look at the St. Louis though, it's a very different play than the Marcellus, obviously, the shale play along with the Upper Devonian and Utica. And the shale plays have a large scope, that's the unconventional part. The Mississippian play is a carbonate. And you've got a chat component and a lime component, but it's more of a conventional play where you have to move a lot of water. When you move to the St. Louis, it's very conventional. You have a really high-permeability, high-quality reservoir there as evidenced by the higher flow rate unlocked with horizontal drilling really. But you've got to find that up on a structure. So you got to have more of a conventional trap, either a closed structure or 3-way closure against the fault or whatever. So they're more distinct -- discrete targets that you're looking at. The good news is our guys have identified a handful of those, and we've leased them. I'm encouraged about future potential for what that can be. But those leases are new, we've got a lot of time. It's high rate of return, we'll drill the next 4 wells and see where we are. And like we talked about, we'll put together our capital spending plan for 2012 into the fall, present it to the board and then typically, we announce it to you guys early next year.

Operator

Our next question comes from the line of Marshall Carver with Capital One Southcoast.

Marshall Carver - Capital One Southcoast, Inc.

Most of my questions were answered but I did have a question. I know at some conferences recently, you've talked about putting together some long-term contracts with ethane users to buy ethane or that you would sell ethane to them primarily for the Appalachian play. Can you update us on any progress there? Any plans for the timing of those contracts?

John Pinkerton

Marshall, it's John. Yes, great question. We've made a lot of progress. And we're getting really, really close on probably our first ethane contract. And the team, Greg Davis and [indiscernible] also helps out enormously on that team as well along with Chad Stephens [ph]. And so we're making really good headway there. We don't -- from what we see today -- and there's lots of really good things that's happening on the ethane front, in terms of a lot of other people are getting into play. And you probably saw Sunoco with their open season on one of their projects up there that's, obviously, a very good move and shows you some of the progress being made. But everything's going great. We ought to have some time before -- either on or before the third quarter, we ought to have something pretty definite that we can tell you. And so it's going along better and faster than I would have hoped. So it's all good there.

Marshall Carver - Capital One Southcoast, Inc.

Okay. And one other question, there was that big Marcellus commissioned report for Pennsylvania filed last week. Was there any -- did you all look through it and were there any surprises in there? Or was it mostly straightforward and what you expected?

John Pinkerton

Well, first of all, we think it was really great leadership by the governor to put the commission together and get all the different stakeholders together, so we could all kind of work on a long-term solution to issues that are out there. So I commend the Governor and the Lieutenant Governor for making it happen. And I also commend all the people who worked on it. We, Ray Walker, who heads up -- who's with us, and obviously, opened up our Marcellus office in Pittsburgh and turned the light on when he was a single employee, and now, we have over 400 people there -- was on the commission and had, obviously, a big role in that. And in all those commissions you have different kinds of people and whatnot. But I think at the end of the day, when you filter through all the recommendations, I think it was an enormous step forward for the state. And now, there's a buffet table there of recommendations. And now, we need to take some real time and effort in smaller groups probably to work on certain of those recommendations that the Governor tells us that are most important and move those forward. At the end of the day, I don't think there were any real surprises to us. A lot of the things that are being recommended, we're already doing in a large way. So from my perspective and I think from Range's perspective, it was really well done, and it's a great step forward. And again, I think it helps to find on both sides expectations from both sides and a lot of different parties involved -- and I think that way -- it's really the first time you got all those constituencies all in one room working together to try to find solutions versus just punching each other in the nose. So I think that's a great step forward, and I think everybody sees the benefit. Clearly, the Governor does and the House and the Senate up in Pennsylvania sees the huge benefit it's already had and will have. So I think it's a great step forward, and I really commend them for the work that was done in a relatively short period of time. But now, the hard work starts. You got to take those recommendations and turn them into something and so -- but I think, again, I think there's a lot of people who really want to make it work so -- including us. So we'll continue to work really hard and dedicate a lot of resource to making sure it's done and quite frankly, done right, which is one of the things that we've always talked about. So pretty excited about it.

Operator

Our next question comes from the line of David Tameron with Wells Fargo Advisors.

David Tameron - Wells Fargo Securities, LLC

A lot of questions have been asked, could you guys talk about -- there's -- you have some permanent acreage position, my understanding is you're drilling a client horizontal, either Sterling or Glaska [ph]. Can you talk about what you're doing out there? Is that true? And if so, what you’re doing out there?

Jeffrey Ventura

I think what you referring to is we've got over 90,000 net acres HBP in our Conger field area. And we have drilled and completed a Penn shale well out there. And we're not going to release results yet. What I can tell you for our very first try, I'm very encouraged by what I've seen so far, and I think the team is as well. But it's early, we need to watch it, and we'll go from there.

David Tameron - Wells Fargo Securities, LLC

Okay, then, could you give us, Jeff, any color on what your next steps are? Is the Penn or its equivalent prospective over your entire acreage position, or can you just -- can you give us anything else?

Jeffrey Ventura

Yes. I can tell you it's prospective over our entire acreage position, so it would be meaningful if it works. If you -- they're oil wells, so you can envision the spacing there. I like talked about the spacing on Tonkawa for their oil wells, even at drilling 12 wells per section, which is – it’s a squirly number, when you divide it out, it’s 53 acres per well, with 12 wells per section. And the Tonkawa gives you a recovery of no greater than 10% of the oil in place. That's the exciting part, yet we're still generating 100% rate of return either through better technology, better completions, better down spacing, you can get higher recoveries. So if you use that same math in a place like Conger, and you use that same exact spacing, you're talking about, if I just punched it out right, 1,700 wells. So it's impactful, and it could be very meaningful, and it's oil. So that's what we're doing out there.

John Pinkerton

Yes. And it's relatively shallow and not all that costly per well too.

David Tameron - Wells Fargo Securities, LLC

Okay. So just -- I guess, I'm going to keep pressing here, you have plans for the rest of the year out there?

Jeffrey Ventura

Yes, for the rest of the year, we're looking at that. We may drill one more well out there, then we'll just watch the production from 1 or 2 wells this year, and then we'll factor in what our program is next year. I think, mainly, we want to understand it, look at the quality and its HBP, and then we'll go from there.

Operator

We are at the end of our allotted time for Q&A. Mr. Pinkerton, I'd like to turn the floor back over to you for any closing comments.

John Pinkerton

Well, thank you, all, for joining us. I know we're a little bit over, and we had lots of great questions. And I appreciate all those that asked questions. Those were terrific questions. And again, we appreciate everybody joining us.

As I mentioned, this is really an exciting time at Range, and we got a lot going on. Even David there who -- I don't know how David does it, but he seems to find out lots of things, so I commend him on that. But we've got a lot going on, and we got a great team, but we're clearly focused and disciplined. And you saw that by our capital spending. We're right on trend with where our capital budget was. And we're going to continue to be disciplined. But it's a really exciting time to be at Range and be a Range shareholder and we couldn't be more happy.

But obviously, that's behind us now. Now we got to -- the bar's set high, and we've got to perform next quarter as well. So we'll get off the phone here and get back to work and get that production up and those costs down, and hopefully, we'll have equal, if not better, results next quarter. So again, thank you very much, and we'll see you around. Thank you.

Operator

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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Source: Range Resources' CEO Discusses Q2 2011 Results - Earnings Call Transcript
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