山脈資源 (RRC) 2011 Q2 法說會逐字稿

Greetings and welcome to the Range Resources Corp second quarter 2011 earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(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 Resource. Thank you. Mr. Waller, you may begin.

Thank you, Operator. Good morning and welcome.

Range reported outstanding results for the second quarter of 2011 with an increase in production and realized prices and a decrease in 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 themes reiterated from each of our speakers today. On the call with me are John Pinkerton, our Chairman and Chief Executive Officer; Jeff Ventura, our President and Chief Operating Officer; and Roger Manny, our Executive Vice President and Chief Financial Officer.

Before turning the call over to John, I'd like to cover a few administrative items. First, we did file our 10-Q with the SEC this morning. It's now available on the home page of our website or you can access it using the SEC's EDGAR system.

In addition, we'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

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 a 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 a 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 decline 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 continue 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. 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.

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. 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. Because the second quarter included 1 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 match the supplemental non-GAAP figures in the press release.

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 5.75% 10-year senior subordinated notes and the full redemption of our $400 million and 6.375% and 7.5% 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. Just as significant, $266 million in second quarter revenue is only $2 million less than the first quarter of this year, even though the second quarter includes just 1 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 analysts' 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 non-cash 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 totaled $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 non-cash compensation but including workovers for the second quarter was $0.65 an 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 an Mcfe. 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 derive more of our production from our lower cost producing regions.

Production taxes for the second quarter were $0.17 an 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 non-cash 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, 5.75% note issuance which replaced $400 million in higher cost debt also explains the one-time non-cash $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 our $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 non-cash stock comp, was $11 million. That's $3 million below last year, due to lower delay rentals offsetting higher seismic expense. The timing of delay 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. 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 deductions. So no Barnett sale proceeds will be lost to tax leakage, as we have ample NOL carry-forwards 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 an 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. 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, lower operating costs and a strong balance sheet from which to enter the next phase of our continued growth.

With that, back to you, John.

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

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 2010 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 Bcfe to 4 Bcfe, and 3.5 Bcfe 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 average 5.7 Bcfe have an average lateral length of 2,802 feet, with a 9-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 t is 5.7 Bcfe. However, many of those companies drilled significantly longer laterals and pumped 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 complete 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 a 105% rate of return in $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 costs 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 fracked 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 derisked. Assuming that 80% of the acreage will be drilled and that 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. Being that we've only drilled and completed a little over 200 horizontal wells, according to this math we have 96% of our wells left to drill. As good as our rates of return 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 in this 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 prospective 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 Mid-Continent division, I'll start with a 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 at 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 will see happen here, as well. Typically the higher recovery factor comes from downspacing 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.

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 1 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 mid-point, 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 laying pipeline connection. When you take this into account, 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 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 $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 have 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 costs, lower operating costs, et cetera.

The second quarter results reflect the lower costs. And the third and fourth quarter results should see further progress in lowering our unit costs. 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 a hugely important event for our Company.

First, the sales proceeds were more than sufficient to retire all of our outstanding bank debt, with the 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 becoming 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 2013 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 projects in place 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.

I'm 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 properties was somewhat of a bold move, as the Barnett properties comprised approximately 20% of our production. However, we believe it best served Range shareholders as it allows Range's shareholders to retain 100% of our 35 TCF to 52 TCF or 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 and our other projects, 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 you've shown us, and we look forward with great pleasure to the second half of 2011.

With that, Operator, why don't we turn the call open for questions.

(Operator Instructions) Ron Mills with Johnson Rice & Company.

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

It's a great question. 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 have significantly fewer stages and shorter laterals. It implies that we have higher quality rock 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 cut. 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 re-emphasize that what we're currently doing in both plays, generates rate of return greater than 100%. So I think the good news, though, is that there's upside beyond where we are today.

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?

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, or 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 1 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, let me 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, we got into the area because we thought it was a good stack pay area and we had a really strong technical team, which is 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. A great stack pay area. And there's 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 continue to expand out the water disposal. And then we moved off-structure and started drilling the Mississippian off-structure with good success. 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 it's a very liquids-rich area.

So we have our water disposal system in there and we will stay ahead of that. The good news there is you've got a great disposal zone directly below you in the Mississippian, in the Arbuckle, very prolific water disposal zone. So I think we're in great shape, strong team. We're building a really exciting acreage position and you'll see us start continual drilling, I believe, next year.

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 last question is 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 an area that you would look to expend incremental capital?

Yes, we're very judiciously picking up additional acreage. And, really, today our acreage position is 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, 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 is 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, we're continuing to acquire additional acreage and I think we can build that. So can we build 1,000, maybe into 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.

David Kistler with Simmons & Company.

Good afternoon, guys. 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 look towards your position in the Marcellus, and specifically focused on 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?

Let me start out by talking a little bit just about the 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, 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 shows and, in some cases, whole cores or sidewall 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, you 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. 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. Last time I mentioned a better well, looked like it might be on the orders 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 around 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 targeted the first 2 Upper Devonian wells, the first well we just targeted away from the Marcellus wells to make sure we had a good clean test. The other one was off of a pad where we had a lot of wells. We wanted to make totally sure the gas was coming from the Upper Devonian, and 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've 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 of some of our Marcellus. I want to just roll back there a little bit. But it's important, I think, in the global question that you asked. When, since Range -- when we pioneered the play and started, we picked Washington County to drill in. We had good success so we continued to drill around there. 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 that could be 6 Bs. 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've got to factor in that we haven't drilled the highest gas in place, biggest, thickest portion yet.

The same is even true with 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 wild card 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. 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 where we're primarily all, for the most part, dry gas.

With that I'll turn it over to John.

I obviously second what Jeff said. In terms of specific, you asked about the BHP Petrohawk deal. I think the key take-away for me on that is, one, hail to Floyd Wilson. 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 that at the end of the day the companies that can drive up their NAV on the most cost-efficient basis, on a per share basis, are the ones that are going to be the big winners. And that's all we're focused on. We 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, are actually going slower 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 will help develop the industry's perception of these other plays. Just like in the Marcellus, we were the first ones to jump 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. That's really good for us because, 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. Again, 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. And so all that's happening and that's all really good for Range and its shareholders.

Again, I think at the end of the day, we're really focused on driving up NAV per share. We understand that all of us have a time horizon. But again, you just look back and you look at some of our presentation materials and you look at the production curve of the Marcellus. 3 years ago we were 20 million a day, then 100 million, then 200 million, then 400 million, then 600 million. And you continue that up and then you add these other formations on and then you add the Upper Devonian, 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 at low cost.

And I think that will continue to transfer into an NAV number. Obviously we've got one that's dramatically higher than we think the stock price is today, 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 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 credit until we prove it and that's what we're all about.

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 for 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 are better. Efficiencies are getting better, offsetting service costs. Should we be thinking 2012 CapEx goes higher as a way to accelerate the increased NAV?

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. We're just now starting to 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, now we're just starting to tinker with that. Jeff and I were just talking about it this morning, in fact. One, it's pretty exciting and we've got a lot of opportunities. And it's good to see our costs coming down because that will allow us to do more. But, yes, 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.

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, one of the great things that we've done, as you mentioned, we've got a great balance sheet. And so it's great to have a great balance sheet. Every once in a while you need to use it, which is what Roger always says. Roger is going to make sure that Jeff and I don't go off the reservation. So we've got a great balance sheet. So to the extent the Mississippian turns out great, or the St. Louis, 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's happened. We've closed the Barnett. We've made up, really, we've made up over 60% of production and we'll have the rest of it made up by the end of the third quarter. 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, grassroots things 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, in the employees, whether it's Pittsburgh or Oklahoma City or Abingdon, Virginia or West Texas, some of the projects we have out there. It's really exciting to be at Range right now.

Great job, thank you so much. Appreciate it.

Gil Yang with Bank of America Merrill Lynch.

Good afternoon. John, you highlighted again, I think you said in the first quarter that in the fourth quarter a lot of the growth is going to come from the backlog of wells that you will complete. Can you just review for us what that backlog is currently and where you expect it to be at the end of the year and what parts of the Marcellus those wells are?

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 will 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 1 in the fourth. And of the 51 awaiting completion, probably 90% of those will be on -- or 80% to 90% -- by the end of the year. And that's where a lot of the growth that John's talked about is going to come from.

Okay, great. You made the comment that the 2009, 2010 program is 5.7 Bcf. If you look at your presentation, your 2011 wells is tracking a little under that. Is there anything going on? Are you drilling different areas? Are you drilling shorter laterals? Are you doing anything peculiar?

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

Okay. I'm just looking at the aggregate data that you show in your presentation.

Yes. That's just a function of some constraints early on. 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 Bs. It came on under constrained conditions of 2.5 million per day, 1.9 million gas and 91 barrels of liquids. Yet, that's 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.

And it sounds like the 2011 program is basically tracking the lateral length and number of stages of the previous 2 years (inaudible), right?

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 fracked a well 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.

Brian Singer with Goldman Sachs.

Thanks. Good afternoon. 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 then what are you thinking about rates of return from drilling the shallower Upper Devonian zones versus what you're seeing in the deeper Marcellus?

When you look at it, it's a combination of 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 Marcellus --and really where we feel it has 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 -- or the Upper Devonian in general, say in the southwest, there's actually on our website you can look at it, there's a pipe 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. Where we've got 80 Bcf to 120 Bcf a section in the Marcellus, the Upper Devonian is about the same. So basically just pick the midpoint, say it's 100 Bs a section in the Marcellus, the Upper Devonian doubles that to 200 Bs a section.

And you go the other way, it's interesting. The Utica, in a lot of cases, is a little bit more than that, it's probably down in that same area, maybe 120 Bs to 140 Bs. So it can be in aggregate over 300 Bs per section. The exciting part is it predominantly stacks 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 intervals. Or the highest, like I was saying earlier, it ends up actually where the highest hydrocarbon in place is, 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. You're going to have roads and well pads and gathering and take-away. So there's really an exciting upside to it.

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

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 or medium term decline rate?

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, to 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.

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? Or is it too early to tell?

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.

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

Well, 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, 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 of a couple 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 will continue to drive them down. As far as specific guidance, I don't know. Roger, I think, has talked about where we expect to be in the fourth quarter and we haven't given guidance I don't think beyond that yet.

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

This is John. I'll be a little bolder here. Yes, I can do that, I guess. I think, Brian, I've got great confidence in our team. One of the things, if you think about the fourth quarter, we're going from 515 million to 520 million in the third quarter, and we're going to 606 million to 611 million in the fourth quarter. If you think about that, 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. 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 people operate those wells in those areas, we've already hired and trained and everything else.

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.

Leo Mariani with RBC Capital Markets.

Good afternoon here, guys. Just wanted to jump into northeast Pennsylvania a little bit more. You guys talked about a 6 Bcf EUR. Just curious as to where the well costs are up there right now.

Let me start with the southwest and I'll move up there. We said in the development mode in the Southwest would be $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. When you look at today off the AFEs 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 million. We just got one, and some wider swing-out, 4.4 million. But a lot of the wells are just a tick over 4 million. So the team's done an 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, in a 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, Mark Whitley just left the room. When 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 believed the team could get them to 4 million in development mode. We're only 200 wells in, we've got 96% of the wells left to drill, and that's probably a conservative number, 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 in terms of where that team, John Applegas 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 the early wells up there, remembering, you're a couple thousand feet deeper than in the southwest. Lycoming County's 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 he's comfortable with 5.2 million. That's Mike Middlebrook's division now. David Dunn and the guys working on that, Brad Grandstaff. 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 to what that team can do.

Great. Just switching gears a little bit over to the Mississippian. You guys clearly picked up more acreage. You've got just over 45,000 net acres now. Just curious as to how much of that you think is derisked by your drilling as well as industry and if you could comment on the well cost there.

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 really good success where we are. If you go off to the west, Sand Ridge and Chesapeake, a long ways away and a whole way from where we are. They have wells close to us but going a long ways out are having a good success. And if you go off to the east, there's some smaller independents that are having good success, as well. I think it's an exciting play. It's a big oil field. And we've got a good position and it's growing. I think it's so far, so good.

Well cost. Right now we're around, we said our drill and complete costs are $2.9 million and we allocated $200,000 of saltwater disposal well to that, to account for. And we just allocated our saltwater disposal well back on a per well basis. And we're close to that now. We're not too far away from that. We really haven't put together, if we literally have 1,000 wells to drill, where do we think we'll be on well 100 or well 150. But, again, we've got great team up there, led by Max Holloway and Bill Coger. And got a great drilling group working for them. I'm sure they'll do great things there, as well, with time.

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

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 is a shale play along with the Upper Devonian and Utica. And 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 a 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 high flow rate, unlocked with horizontal drilling, really. But you've got to find that up on a structure. So you've 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 have leased them. I'm encouraged by future potential for what that can be. 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 in early next year.

Marshall Carver with Capital One Southcoast.

All right, good afternoon. 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?

Marshall, this is 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 the team, and Rodney also helps out enormously on that team, as well, along with Chad Stevens. And so we're making really good headway there. From what we see today, there's lots of really good things that's happening on the ethane front in terms of a lot of other people are getting in the play. You probably saw Sunoco with their open season on one of their projects up there. That's obviously very good news. It shows you some of the progress being made. But everything's going great. We ought to have sometime 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.

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

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 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 that worked on it. Ray Walker, 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 what-not. 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 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 define on both sides expectations from both sides. A lot of different parties involved. And I think that way, it was really the first time you got all those constituencies all in 1 room working together, trying to find solutions, versus just punching each other in the nose. I think that's a great step forward. 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. 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've got to take those recommendations and turn them into something. But I think, again, I think there's a lot of people who really want to make it work, 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.

David Tameron with Wells Fargo Advisors.

Thank you. Good afternoon, nice quarter. A lot of questions been asked. Could you guys talk about, you have some Permian acreage position. My understanding is you're drilling a horizontal either Sterling or glass. Can you talk about what you're doing out there? Is that true? And if so, what you're doing out there?

I think what you're 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.

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

Yes, I can tell you it's prospective over our entire acreage position so it would be meaningful if it works. They're oil wells. So you can envision the spacing there, like I talked about the spacing on the Tonkawa for their oil wells, even at drilling 12 wells per section. Which is a squirrelly number. When you divide it out, it's 53 acres per well. But 12 wells per section in the Tonkawa gives you a recovery of no greater than 10% of the oil in place. That's the exciting part. Yet you're still generating 100% rate of return, either through better technology, better completions, better downspacing. You can get higher recoveries. So if you use that same math in a place like Conger, and you use the same exact spacing, you're talking about, if I just punched it outright, 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.

And it's relatively shallow and not all that cost, too.

Okay. I'm going to keep pressing. Your plans for the rest of the year out there?

For the rest of the year, we're looking at that. We may drill 1 more well out there. And 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 it's HPP and we'll go from there.

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.

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've got a lot going on. Even David there, 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've got a great team. But we're clearly focused and disciplined. You saw that by our capital spending. We were right on trend with where the capital budget was and we're going to continue to be disciplined. 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. We've got the bar 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. Again, thank you very much and we'll see you around. Thank you.

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