山脈資源 (RRC) 2012 Q1 法說會逐字稿

Welcome to the Range Resources first quarter 2012 earnings conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in the conference call that are not historical facts are forward-looking statements. Such statements are subjects to risks and uncertainties, which could cause actual results differ to materially from those in the forward-looking statements. After the speakers remarks there will be a question and answer period.

At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead sir.

Thank you, operator. Good morning and welcome. Range reported outstanding results for the first quarter with a continued increase in production, and a decrees in unit costs. Both earnings and cash flow per share results were greater than First Call consensus. Our speakers on today's call are Jeff Ventura, President and Chief Executive Officer, Ray Walker, Senior Vice President and Chief Operating Officer, and Roger Manny, Executive Vice President and Chief Financial Officer. Range has filed our 10-Qwith the SEC yesterday, it is now available on the homepage of our website, or you can access it used the EDGAR system.

In addition, we have posted on our website supplemental tables which will guide you in the calculation of non-GAAP measures of cash flow, EBIDAX, cash margins, and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today. We have also added tables which will guide you in modeling our future realized prices of natural gas, crude oil, and natural gas liquids. Detailed information of our current hedge position by quarter also included on the website.

Now let me turn the call over to Jeff.

Thank you, Rodney. I will begin with an overview of the Company. Ray will follow with an operations update, and Roger will be next with a discussion of our financial position, then we will open it up for Q&A. Range is on track to achieve the targets that were set for 2012, we are on track to grow production 30% to 35% year-over-year, exit the Marcellus at our goal of 600 million cubic feet per day net, and to grow liquids production 40% year-over-year. We are also making good progress in all five of our enhancement areas, which are the Super Rich Marcellus,Super Rich Upper Devonian, Wet Utica, Horizontal Mississippian oil play, and Cline Shale oil play. Ray will give more details on all five projects in his talk.

Financially we are also in good shape and making good progress as well. During the quarter Range continued to lower its cost structure. On the units of production basis our companies five largest cost categories fell by 6% in aggregate compared to the prior year period. Our natural gas hedge position is excellent for 2012, we are 75% hedged at a floor price of $4.45 per Mmbtu. We recently completed our bank redetermination and reaffirmed our borrowing base under the bank credit facility at $2 billion, and increased our commitment amount to $1.75 billion. We have no debt maturities until 2016 under our bank facility, and 2017 for our notes.

I want to highlight the great job that Roger and his team did on the recent $600 million bond offering, which resulted in the lowest interest rate ever by a BB rated company in any industry. We issued the notes at a fixed rate of 5% for 10.5 years. Most importantly, in today's environment of low natural gas price and high oil price, all of Range's key projects generate attractive rates of return. 75% of our 2012 capital is going into liquids rich projects, almost all of which is wet or super rich Marcellus or the horizontal Mississippian oil play. The rates of return of these projects range from about 70% to 100% at strip pricing. Almost all of the remaining drilling capital is going into the Northeast Marcellus, where the rate of return is in the mid-20% to low-30%. We will be decreasing our rig count in the Northeast to roughly one rig by the end of this year, and refocus more of our capital into the higher return areas.

Historically, it was important to be in the core part of a particular play. Given the disparity in oil and natural gas prices, it is now not only important to be in the core part, but you have to be in the wet core. Also not all of the plays are created equal. Some plays don't have wet cores or wet areas at all. Other plays do, but are higher cost and lower return. Fortunately, Range has a huge acreage position in the wet part of the core in one of the best rate of return plays in the US, which is a southwest part of the Marcellus. We also have a large position in what we believe is the core of the horizontal Mississippian oil play in Oklahoma and southern Kansas. This is one of the highest rated return plays in the US.

Plus we have tremendous upside in the super rich and wet upper Devonian, wet Utica, and the Cline Shale oil play. Including only our five enhancement areas, we have about 800,000 net acres in the liquids rich portfolio, in our liquids rich portfolio that are prospective for wet gas, super rich gas, or oil. Differentiation between companies at this point in our industry is key. The key question is which companies can make good returns in today's price environment. At Range, we expect to drive up production in reserves per share on a debt adjusted basis for years to come, with strong returns and low costs even in today's environment. We will do so while staying focused on safety and being good stewards of the environment.

At the IPAA Conference in New York last week, there was a lot of interest in Range from fund managers and analysts. Some of the feedback that I heard from the meetings was that in this environment, investors are seeking E&P stocks that offer both significant downside protection, and significant upside per share, and Range is one of them. That is great feedback to hear in any environment, and we are proud to have earned that trust.

I will turn the call over to Ray to discuss operations.

Thanks, Jeff. My comments today will cover several topics. I will talk about costs, efficiencies, well performance, production guidance, and give some operation updates from our divisions. Like Jeff said, we are off to an excellent start to meet our production growth targets in 2012. Our plan to shift more of our resources in capital and investment to liquids rich and oil projects is on schedule, and we can see that it is already beginning to pay off.

As we stated in our earnings release, the first quarter production came in at 655.0 million cubic feet equivalent per day, which was comprised of 512.5 million gas, 17,152 barrels of NGLs, and 6,682 barrels of oil and condensate. I think it is also important to characterize the types of production specifically. While we do produce a lot of gas, I don't think most folks realize that 71% of our total production is coming from our liquids rich and oil plays. All of that rich gas has significant BTU and liquids upgrades, and therefore has significantly more value than the dry gas.

We had only 29% of our total production coming from dry gas areas in the first quarter. For example, looking at slide 19 of our investor presentation on the website, which focuses on southwest PA, and not considering hedging, we would simplistically say that we are getting 3.2 times the realized price for our wet gas verses our dry gas in southwest PA. Again, the largest portion of our gas production is rich gas, with significant BTU and liquids upgrades from our liquids rich and oil areas.

While this year approximately 25% of our capital budget is directed to the dry gas areas of our portfolio, if the current commodity price environment persists, you will see us cut our spending in the dry gas areas significantly at the end of this year, once we have completed the majority of our HBP drills in northeast Pennsylvania.

Production guidance for the second quarter is 715 million cubic feet equivalent per day net, comprised of 6,000 barrels of oil, 18,500 barrels of NGLs, and 568 million cubic feet per day of gas. In order to answer a few questions in advance that you would logically have, the liquids growth that we have projected for the year is heavily weighted towards the third and fourth quarter, as it simply takes time for the new drilling in the liquids rich and oil areas to kick in. You should expect to see the different components growing at different rates throughout this year. In fact, you may notice that the oil rate for the second quarter is actually less than the first quarter. It is basically a result of timing for new wells and infrastructure coming online throughout the year. These fluctuations are simply necessary for all of the advanced planning for our drilling program and infrastructure development that is underway.

In the Marcellus we have brought on line some great wells in the first quarter. For example, sales from a 10-well pad in the wet area which had a working interest of 97%, and an NRI of 82.4% began in the middle of March. Initial production from that pad was approximately 30 million a day equivalent from two wells. However, the wells were constrained due to equipment limitations. Six days later after installing additional equipment, the rate off the pad was increased to 45 million a day from just three of those ten wells. This flow period lasted about 28 days.

After changing equipment at the compressor station, production from this same pad was ramped up to approximately 75 million per day. This rate has been steady for four days and at present a total of seven wells out of the ten wells are producing with the other three wells still shut in as we are still capacity constrained to 75 million. The average lateral link for these wells is 2,763 feet, with an average of 10 frac stages each, and none of the wells had reduced cluster spacing completions. Again, reduced cluster spacing is simply a technique utilizing clusters of perforations that are placed closer together along the lateral. I will refer to the reduced cluster technique as RCS throughout the rest of our remarks.

This ten well pad in the wet area of the Marcellus is a great example of our engineering and operating teams recognizing the potential production volumes, and in very short order eliminating constraints in order to produce the additional volumes. These particular wells are also much better than the offsets, due to some reservoir and rock properties analysis, that our team has come up with to determine the best target for the horizontal lateral in the Marcellus. At no additional cost, and by simply landing the lateral in a different part of the Marcellus, we achieved greatly enhanced production performance. As we combine this technique along with RCS techniques, moderately longer laterals, and increased conductivity frac designs, we expect to see continued improvement and capital efficiency in well performance going forward.

Shifting to northeast Pennsylvania, in Lycoming County we recently brought on line four new horizontal wells that produced the sales at 24 IPs of 26 million, 23 million, 21 million, and 18 million a day respectively. Those wells had an average lateral length of 3,000-foot in ten stages, and were 100% working interest in approximately 85% NRI wells. As you can see our technical teams are continuing to make great progress in enhancing our well performance in this area. We plan to bring online 45 more wells in this area in 2012, and again like Jeff said, we will decrease activity to the 1 to 1.5 rig level at year end, as we HPB the majority of that acreage with this year's drilling program.

Now let me spend just a few minutes on cost and efficiency improvements. Our operating and technical teams in all of the divisions continue to do a great job in driving down unit cost. Our LOE for the first quarter was $0.48 per MCFe, and we continue to see progress in that area. Roger will be giving guidance for the second quarter LOEs in just a few minutes.

As important as making improvements in costs and well performance, we are also making great improvements in operational efficiencies. Significant gains in efficiencies will serve us well as we continue to learn to do more with less, especially in this gas price environment. Year-over-year 2011 versus 2010 we saw drilling efficiency improvement in our southern Marcellus operations of up to 50%. We drilled 34% more horizontal wells in 2011 with 11% fewer rigs. That is a huge improvement in anyone's book.

On the completion side, we saw equally impressive metrics when comparing 2011 to 2010. In 2011, we saw a 53% increase in frac efficiency compared to 2010. The improvement was as a result of our key performance indicator process which focuses on equipment and location personnel. It simply utilizes gap identification to identify opportunities to work faster and smarter. This 53% improvement in frac efficiency composite translates to 12% composite average of savings in our overall completion costs. We are also seeing very good improvement in service pricing. Recently renegotiated frac contracts are expected to translate to a 4% to 5% improvement in total well costs, and literally save usmillions of dollars going forward. We are really proud of those operating teams. These efficiency and cost improvements are truly great accomplishments, that will play a significant role in maintaining and improving our low cost structure, while enabling improved capital efficiency going forward.

Now some updates from our liquid rich and oil areas. We just brought online our first three 2012 Super Rich Marcellus wells, and while it is way too early to talk about rates the wells appear to be meeting our expectations. For some very recent and very noteworthy news, flowback operations on one of the wet area wells located on a 3-well pad just at-the-edge or the border between the super rich and the wet area began just last week. We announced in our press release that the peak 24-hour production from that well which has 100% working interest and 84% NRI, was 7.1 million cubic feet of gas, 108 barrels of condensate, and 501 barrels of NGLs, not including ethane. If we were extracting ethane, that would translate to 6 million of gas and over 1,300 barrels per day of liquids.

The well's lateral length was 2,752, and it was completed with 14 stages, using the RCS method. and the new targeting of the lateral. The production from the well is approximately 1,340 BTU gas, which again puts it right in the edge of the super rich area. In fact, the well has gotten even better as we have opened it up. I just got a report this mourning and for the last 24 hours the well made 168 barrels of condensate, 578 barrels of NGLs, and 8.1 million of gas. That is almost 750 barrels of liquids not counting ethane, if we counted ethane it would be 1,547 barrels, with 7 million cubic feet of gas. This well certainly bodes well for the super rich area of potential, and based on this well's initial results, we believe the new targeting methods and the RCS style completions could significantly improve performance in both the wet and super rich areas.

We now have seven rigs running in the Super Rich Marcellus, and expect to have approximately 15 new wells in that area online in the second quarter. As we progress throughout the year, we plan to keep you updated quarter by quarter with results from this area. According to our current development schedule, which is always changing and adapting, there will be approximately 50 more wells brought online this year in the super rich Marcellus during the third and fourth quarter. This means that as of today, our plans are now to bring online approximately 65 wells in the super rich Marcellus in 2012. In addition to the 28 wells brought online during the first quarter in the wet Marcellus area, there are approximately 50 more wells planned to come online in the wet area during the next three quarters. And of course, there will be a handful of delineation and commitment wells drilled in other areas of southwest PA throughout the year.

We are just getting started in the super rich upper Devonian Shale, and have now fraced our first well and are literally commencing flowback operations as we speak. We are also currently drilling the second will. We have rotary sidewell cores in two super rich Upper Devonian wells, and although we have not completed these wells yet, I will give you some preliminary observations. We see TOCs of up to 11%, porosity is up to 8%, and permeability measuring all of the way up to 700 nano-Darcies. For those without ready reference to the technical data for comparison, or in simpler terms in English, this is very encouraging.

In addition we saw the best mud log shows that we have seen to date across any Upper Devonian Shale. Now I will use some really technical terms, one set of the cores was oozing condensate, and the other cores from the other well were dripping condensate. Needless to say, everything we see today supports our hypothesis that the super rich Upper Devonian could be a very nice liquids rich play.

Shifting to the horizontal Mississippian oil play in Oklahoma, we now have two rigs running and have brought on a first two new wells. The average IP of those wells is 525 BOE per day, which is 320 barrels of oil, 117 barrels of NGLs, and 530 MCF of gas. And although still very early, they are well above our performance expectations. These wells had an average lateral length of 2,700 feet in 15 stages, with 100% working interest and 81.5% NRIs. We have also increased our acres position to about 145,000 net acres.

As it is still early in this play, and as we continue to closely watch our results, it is part of our overall goal to continue to shift our focus towards the very highest rate of return projects across the Company, and this is surely one of those. Infrastructure, both midstream and salt water disposal are coming together nicely, and we are on schedule to significantly ramp up production from this area as we move into next year. Our technical team also continues to gather data and monitor activity in the wet Utica area of NW PA. Mainly we appear to be right on strike with several great wells that have been released recently by other companies. Offset leasing activity and drilling plans announced by offset operators are all confirmation of a potential liquids rich play. Propriety log and core data that we recently obtained continues to support that this area is highly prospective for liquids rich and condensate production. We feel our 190,000 net acres which is primarily HPB, is positioned well and we are still on track to drill our first wet Utica well this summer. We now plan to also drill a second well later in the year that you can now see located on our updated investor presentation map of the Utica wet area.

The Cline oil horizontal play at Conger is really picking up steam. We will be moving a rig in this quarter to begin drilling three wells across that acreage. Devon has permitted three wells directly offsetting our lease line to the east, and is now illustrated in our investor presentation. One of those wells is just 2.5 miles from our lease line, and the other operators in the areas have four rigs running. The IP of the second Cline well was 484 Boe per day, which was 282 barrels of oil, 123 barrels of NGLs, and 476 MCF of gas. And it was completed with 11 of 16 successful frac stages with a lateral length of approximately 4,500 feet. The first well was also about 4,500 feet of lateral, and had seven of ten stages successfully completed.

As you can tell, we are still learning and optimizing. Even though neither of these completions was 100% successfully completed, the results still fit right in line with our expectations, and as we test the acreage with different targets, lateral links, different completion designs, we believe our technical team can significantly improve results going forward. All of this information will be helpful in derisking our 100 now net acre position, which again is 90% HPB. Another point to make here, as well as in any area of horizontal development is to compare apples-to-apples when talking about production performance from differing lateral lengths and number of stages per lateral. As always, what we do here at Range is continue to optimize lateral links and number of stages, to obtain the best rate of return from the project. What we really compare when looking at different well designs is the resulting return on investment.

Our technical teams continue to do a outstanding job with our legacy stack pay assets. In addition to the Cline Shale, the Permian team recently completed its second vertical Wolfberry well on our Conger Field properties, at an initial production rate to sales of 517 BOE per day, which was 212 barrels of oil, 144 barrels of NGLs, and 969 MCF of gas. The first Wolfberry well had an initial production rate to sales of 495 BOE per day, which was 195 barrels of oil, 141 barrels of NGLs, and 954 MCF of gas.

These wells are 100% working interest and 75% NRI, with approximately 1,200 feet of stack pay, and were completed with 11 and 12 stages. The average 90 day production to sales for the first well was 204 BOE per day, which again was 59 barrels of oil, 83 barrels of NGLs, and 372 MCF of gas. Range has the potential for an additional 100 to 150 vertical Wolfberry locations on 40-acre spacing at Conger. I should point out that some operators in the area are discussing the potential of, and some are already drilling on 20-acre spacing. And we can certainly see that same potential here. The confirmation of the potential here I will also point out that there are 33 rigs in the area drilling Wolfberry wells.

We plan to drill two additional vertical Wolfberry wells this summer, while we have the rig out there drilling the Cline wells. We will drill one vertical Wolfberry, then the three horizontal Cline wells, and then finish with the second vertical Wolfberry well. Infrastructure, transportation, and marketing are all on track for all products in all areas. We currently believe we have plenty of firm transportation, plenty of sales along with plans to keep our gathering compression and processing capacity well out in front of our liquids rich developments into the future.

As much as our drilling results are a testament to our technical teams, I am also really proud of their progress in the areas of safety and environmental production. We continue to make improvements in handling our fluids across all of our operations. For 2011, our spill rate when handling produced water, flow back water, or oil and condensate was 0.0025%, or more simply said, 25/10,000th of 1%. While it is still not zero, which is our constant goal, this is indeed an accomplishment to be proud of. In fact, we have already seen a 17% improvement in that statistic during the first quarter versus a year ago. Our teams are absolutely committed to and will never be satisfied until we get to zero spills going forward. At the same time, we achieved a 50% reduction in reportable incidents during the first quarter, along with a 60% reduction in days away restricted and transferred incidents. Or what we used to call lost time incidents.

Our total recordable incident rate was 0.76 which is well below our 2011 peer group average of 0.99. As always we strive for no incidents, and we surely never want anyone to be hurt or injured, but we are very proud of the way our teams have continued their focus on safety and environmental protection, and are today maintaining a culture. throughout the organization, that truly supports one of our primary core values at Range.

All-in-all we had a great first quarter, and we are well positioned for the future. Our employees continue to do a great job, and our shift over the past couple of years to liquids and oil plays is really beginning to pay off. Our already low cost structure is steadily improving, and we are continuing to recognize improving efficiencies along with improving well performance. We are right on track to meet our goals, and we plan to continue to deliver what we say we will.

Now over to Roger.

Thank you, Ray. Like last quarter, I will start with the balance sheet, and then work over to the income statement. Range strengthened its balance sheet in the first quarter through three actions designed to bolster liquidity and reduce risk. First in February we issued $600 million of 5% 10.5-year no call five senior subordinated notes. Proceeds were used to repay bank debt, and prefund a portion of our 2012 drilling program. With $123 million in cash on hand left at the end of the first quarter. These long term fixed rate notes help insulate Range from the interest rate volatility, and better match the average life of our assets to the liabilities that fund them.

Second, in March, we requested and in April received, a reaffirmation of our $2 billion bank credit facility borrowing base. And we increased the credit facility amount commitment from $1.5 billion to $1.75 billion. Lastly, we added three new North American banks to the credit facility. The addition of three new banks combined with the refinancing of floating rate short term bank debt with long term fixed rate notes, lessens our balance sheet risk, while the increase in the commitment amount increases our liquidity.

Turning to the income statement, cash flow for the first quarter was $163 million. Roughly equal to the first quarter of last year. Cash flow per share was $1.02. $0.05 per share over analyst consensus estimates. EBIDAX for the first quarter was $198 million. Also roughly equal to last year's figure. Cash margin for the quarter was $2.68 per MCFE, 19% lower than last year, due to declining prices outpacing declining cash expenses. Earnings calculated using analysts methodology were $24 million, or $0.15 per share. That is $0.02 above analyst consensus estimates. Our website contains full reconciliations of these non-GAAP figures to GAAP. In addition to several supplemental tables breaking out results from Barnett discontinued operations.

Moving to the expense categories and second quarter guidance figures, we are pleased to report another quarter of reduced unit cost expenses. Direct operating costs including workovers was $0.48 per MCFE, 36% lower than last year's first quarter figure of $0.75, due to reductions in water handling costs, low service costs, and equipment rentals. Operating costs also benefiting from unseasonally mild winter weather. We expect unit costs operating expense to be in the $0.51 to $0.53 range for the second quarter of this year, as we have scheduled some extended equipment rentals to bring on several new multi-well pads. Third-party transportation gathering and compression expense is now broken out on the separate line item as opposed to netting the expense against revenue.

On a unit cost basis, transportation gathering and compression experience was $0.68 in the first quarter, up from $0.56 last year. We came in slightly over guidance on this item in the first quarter, due to some prior period adjustments. Second quarter expense, should be approximately $0.63 per MCFE. The DD&A rate for the first quarter was $1.68 an MCFE,that is $0.03 higher than 2011's first quarter,due to the Barnett assets being held for sale last year. The DD&A rate may fluctuate a few cents up or down with production mix during the next quarter. And a more significant downward change should occur later this year, as we re-evaluate our prudent reserves.

The first quarter marks the debut of the Pennsylvania impact fee,which we are combining with the production tax line and Ad valorem tax line on the income statement. The character of the impact fee is somewhat different than traditional production taxes, in that the primary driver of the fee is the number and timing of wells drilled. There is not yet a clear consensus among companies and accounting firms regarding the best way to account for the Pennsylvania impact fee, therefore you may observe differences in how the fee is recorded by other companies, and you may see differences in how Range presents the fee in future periods to conform to industry norms. But in the meantime, we will be providing quarterly guidance for the Pennsylvania impact fee, on an absolutely dollar basis, and production tax guidance for the non-Pennsylvania production on a unit cost basis spread across total company production.

The $24 million retroactive impact fee component for wells drilled prior to 2012 that we mentioned on the last earnings call, is passing through the first quarter of 2012 as a special item. There is also a $6.2 million current year impact fee provision representing the first quarter accrual for wells drilled so far in 2012. And the carry over from wells drilled in prior periods. First quarter production and ad valorem taxes for the Company's non-Pennsylvania properties totals $0.11 per MCFE.

Now in the second quarter, based on currently projected drilling, we anticipate the Pennsylvania impact fee will be approximately $6 million. Total Company production and severance taxes for the second quarter are expected to be $0.12 per MCFE, plus the $6 million impact fee. G&A expense, adjusted for noncash stock compensation and other recurring items for the first quarter was $0.50 an MCFE, $0.05 below last year. Unit cost G&A in the first quarter benefited from a nonrecurring expense offset of $0.03 an MCFE, so we expect second quarter G&A expense to be in the $0.52 to $0.54 per MCFE range.

Interest expense for the first quarter was $0.62 an MCFE, down considerably from the $0.73 figure last year, when our leverage peaked just before the Barnett sale. And due to the new fixed rate notes bearing higher interest costs in the current floating rate bank debt, we anticipate second quarter interest expense to come in right around $0.66 an MCFE. First quarter exploration expense excluding noncash compensation was $21 million, $5 million below last year, due to the timing of our seismic expenditures. The second quarter should see exploration expense between $23 million and $25 million, due to increased seismic spending that was originally slated to occur in the first quarter. Please remember, that Range does not capitalize any of its exploratory or developmental seismic expense. Unproved property and abandonment and impairment for the first quarter came in at $20 million, that is up $3 million from year. Second quarter unproved property impairment is expected to be between $20 million and $22 million.

As Jeff mentioned at the opening, approximately 75% of our 2012 natural gas production is hedged at a floor price of $4.45 an MMBTU. Also we swapped additional 2013 natural gas volumes during the quarter, bringing our 2013 natural gas hedge volume to $343 million per day, at a floor price of $4.41 an MMBTU. We increased our 2012 NGL hedges to 12,000 barrels per day, at price of $96.28 per barrel. A summary of all of our hedge positions appears in the press release tables, and full hedging detail may be found on our website.

The first quarter saw continued improvement in our cost structure and balance sheet, with available liquidity at a record high. While everything is on track for the year, because of the timing of leasehold expenditures the first half of 2012 will see a front loading of capital spending, while the back half of 2012 will see stronger production growth. In summary, despite significantly lower natural gas prices in this year's first quarter, we kept cash flow even with last year, while hitting all of our marks on the operating side. Jeff, back over to you.

Operator, let's open it up for Q&A.

Thank you. (Operator Instructions). Our first question comes from the line of Brian Singer, Goldman Sachs, please proceed with your question. Mr. Singer, are you there? Our next question comes from the line of Pearce Hammond from Simmons and Company, please proceed with your question.

Good afternoon.

Hello.

You intent $75 million on land this quarter, is that one-time in nature? Could that bias total CapEx higher throughout the year? And then how is that allocated, was that all in the miss line?

No, capital we are confident we will stick to the $1.6 billion for the year, so we will be at that number. Along with the 30% to 35% production growth, and 40% increase in liquids. So we are on track there. The land is all targeted, either towards the wet or super rich part of the Marcellus, of course that stacks with the wet and super rich part of the Upper Devonian or the Mississippian. So that is where we are spending of all our money.

Thanks, Jeff, and then with the announcement of your prolific vertical Wolfberry wells, would you consider reallocating additional capital to that play this year? And then how did the economics of that play compete with some of your other areas?

Yes, it has been good news. The team did a really good job of coming up with an opportunity, and I am going to step back for a minute. I think a lot of what you see is typical across our areas. We get into areas that have stack pays, rich hydrocarbon charge, and really good technical teams working those areas. What that allows is for opportunities year after year after year, as those guys figure out new things and new ways to increase recovery factor. So that is very typical of the Range portfolio. It is a great opportunity. The wells are performing strongly, in fact if you compare them other operators and other analogous production out there, it is granted just the first two wells but they compare very favorably.

The rates of return look strong, we were actually debating whether to do them on this call, and decided to wait maybe another quarter, maybe do them on the second quarter. But they are strong rates of return, we will drill a couple more wells this year like Ray said, it is an exciting opportunity, 100 to 150 locations at 40-acre spacing. I feel comfortable in time. It is probably more likely we will be double that, because it is more likely 20's or lower spacing, given the thick section, and high amount of hydrocarbon in place. But I think we will stay on track. That is an exciting opportunity, but the Cline is equally exciting. The Cline covers the entire 100,000 acre position at 50-acre spacing that is potentially 2,000 wells. And you can see knowledgeable Permian players all around us now targeting and drilling it. So the more we understand and unlock the Cline, both are great opportunities. The Cline just has a lot more running room.

One final question, which you addressed in your prepared remarks, the decline in oil volumes from Q1 to Q2 based on your guidance, can you put a little more color around some of these infrastructure constraints? thatare leading to that?

Yes, and that is a good question. Basically it is just an artifact of wells coming online, and timing with infrastructure that is being planned. I mean like we talked about in the last quarter, a lot of these projects we have been working on for a couple of years. And part of that is putting together midstream deals, and things like that. And so to make a long story short, it really just an artifact of the point that even though we are breaking on some of the new horizontal Mississippi oil wells, they are just now coming on line, and we just aren't going to see a lot of increase in production until we get into the third and fourth quarter. And a lot of that is going to be driven by the increased amount of activity that we have got in the wet and super rich Marcellus area. And that stuff is just simply an artifact of the wells coming on line. So what you are seeing is the wells we brought online in the first quarter just naturally declining off. And we are just not adding that many wells in the second quarter.

The important point though, is way are still on track.

Yes.

For 40% year-over-year growth.

Thanks, guys.

Thank you.

Our next question comes from the line of Brian Singer from Goldman Sachs, please proceed with your question.

Come on, Brian. (laughter)

Can you hear me okay?Alright. Sorry about that earlier. A couple of questions. First on the, with regards to your reduced cluster spacing, can you talk about how widely you expect to use that across your Marcellus acreage? And what that does in terms of well costs relative to your standard completion?

Great question, Brian. The reducing cluster spacing is a technique, it is really one of four different things that we are working on right now. There is reduced cluster spacing. There is going to moderately longer laterals. There is increased conductivity frac designs, which is simply putting more higher conductivity fractures that could potentially could be smaller jobs pumped. And then better targeting of the lateral in the rock. And so it is, we very seldom as much as we would want to, just try one of those things at a time. You never really get that opportunity to do that. So it is really hard to say that a certain amount of cost increase is associated with RCS, versus smaller frac jobs, because we will be combining all of those going forward.

The answer is yes, it does cost more to put the perforations closer together, because we are doing more of it, and it does cost more to do more frac jobs along the lateral. And in some cases if we are steering the well a little more, it may cost more to steer the well while we are drilling. What we are really focused on like I said in my prepared remarks, is when we get to the production results looking at the return on investment of all of those various combinations, and with the, we have got seven rigs running in the super rich today, we will be adding a lot of data to analyze over the next coming months and quarters. And so I think really we will have a good feel for how all of those things effect our results going forward. But the important thing is, everything we have done to date says that we are getting belt err results. But I am reluctant at this point because it is so early to tell you that a certain amount is attributed to RCS, versus lower laterals, or whatever else we are doing.

I would just like to add on to what Ray said. I think the important part is if you look at the economics we put for the southwest PA wet Marcellus, under strip pricing or whatever is out there on the website. That generates a 73% rate of return, which are excellent economics. And that doesn't incorporate all of the things that Ray was saying. So there is a chance as good as 73% is, it can get better.

Same thing when we announced the eight wells in the super rich originally, that is the economics out on our website that you can look at, they are actually even better. They went up to a 95% rate of return at the strip pricing that is on the slide there. But there is a chance you can enhance that, because we did not apply all of those things to either of those. So as good as it is, the opportunity exists that the economics could be really enhanced in both areas.

Do you expect that given that these wells are producing at twice the initial rate, do you expect a normal course decline curve that will then lead to twice the EUR, or do you expect a steeper decline curve.

Well, we can certainly hope for twice the EUR, but I think at this point it is too early to know. IPs are not necessarily as good a judge of the character of a well's performance, long term is what they used to be in the old days. One simple reason, certainly in the Marcellus is there are very few wells that ever come on line that aren't constrained somewhat, due to compression or gathering, or whatever. So the answer is we are really encouraged with what we see. And like Jeff said, the important thing is every decision we do here is driven towards trying to get a higher return on the investment that we make. And all of these things we are trying we believe will drive those returns that we have got in our investor presentation up even higher. And that is what we are really shooting for.

And another key thing there, when you look at those economics like I just referred to, in the super rich, we had the eight wells originally that we announced on the last call, where I gave you more a little more color this time. But those original eight wells have been online for an average of about year and a half, so those aren't 24 hour IPs, or 7-day or 30-day, that is a year and a half worth of data.

Great, thanks. And then very quickly, in Bradford County where you have the non-operated position, is that all acreage that is held by production, or do you see any acreage expiration issues, given the lack of drilling because of pricing?

One I like to point out, that whole position is about 14,000-acres, so it is really small. Relative to the over 1 million acres net that we have in the state, it is a tiny, tiny fraction. A lot of it is held maybe a little bit of the 14,000 goes away. It is in the dry gas area, is and they have actually gone down to zero rigs in that area.

Great, thank you.

Thank you, Brian.

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

Good afternoon, guys. Ray, just a quick follow up on the RCS. A sense in terms of how many more clusters are you doing per stage under the RCS method versus your prior method.

Well, I don't know that we are locked into a specific space in between clusters yet. But I can tell you I think most of the recent stuff we are doing is we have gone from three clusters originally in our completions, we were three clusters spaced 100 feet between. Basically three clusters in a 300-foot interval, now we are three clusters in a 200-foot interval. But that could change. We have experimented I think all the way down to 150, and we have actually gone even longer than 300 again, trying to figure out what the optimum is.

Okay. And from a lateral placement, can you talk about what you are doing differently, and a little bit maybe provide a little bit more color on what the analysis suggestion in terms of why you are changing the placement of the lateral, and how much of an impact do you think that a simple lateral placement could have on EURs or well performance?

Well, I think being a guy that has fraced a bunch of wells in my career, a year or so ago I would have said it wouldn't make any difference, because we are going to bust it all up when we frac it. But today I will tell you that the guys have made a real impression on me that it does make a big difference. And I think it has to with a lot of complicated things which I won't go into here, because it would take the rest of the call, and we don't want to give away our secrets. But essentially, it is a lot of analysis of rock mechanics, and characteristics of the rock, that determine how the fracture initiates, and actually how it produces in the early stages of the well life, and so forth. We are confident that we are seeing definite improvements. By better targeting, it is going to be different across the play.

Again the Marcellus is a huge play, and just driving from one side of the wet to the other side of the super rich, that is an hour drive. In a car, so it is a big area and it is going to change a lot. What's critical is just like Jeff talked about earlier, in his remarks, just seeing that the technical team given more time and more data, and allowing them to use the tools and the diagnostics that they want to, has really paid off for us. I fully expect that we will keep seeing improvements going forward.

Great. And then shifting down to the Permian, is it fair to assume based on the comment that the Cline covers the whole position that the Wolfberry portion of the play is combined to the western portion of your Conger field?

That is exactly right. That is fair.

That is why we gave you a well count, rather Nan acres. It is 100, to 150 at 40s, and then obviously to 200 to 300 of 20s.

Do you think there is something going on as you are at that eastern portion of the basin, that is different than what the industry has been doing whether it is rocks or whatever, given that those wells versus a typical Wolfberry well is significantly higher, or was there something range specific in terms of operations that you think drove those results?

Well, we have only done a handful of wells, so I would hazard to say that we are any better than anybody else. But it is probably more of the rocks than anything else right there. But again, like Jeff said, that is why we put the well count out there, it is not huge, but it is definitely significant. And it is a great opportunity, and something our technical teams did really well. They looked at a concept, and figured out a different way to approach it, and made some great rate of returns. It is a great way to ramp up some oil production. And we are excited. I think we will have a great opportunity going forward to really ramp up some oil production there.

Yes, to me there are two things that are exciting. Regardless of the reason, I am always excited when our wells are performing really well. And like Ray said, initially it is probably the quality of the rock, and the fact that we hopefully can repeat that across multiple opportunities. In aggregate, when you look at say we have 300 wells to drill, it is not going to really drive our reserves or resource potential, but it can really significantly drive our oil production over the next year or two, or three or four, and that is the exciting part about it is more high rate opportunities that really work in today's environment, plus it is in essence free acreage. It is back to having stack paid high quality technical team. It is nothing we acquired, it is that something we had. Is then you get all the efficiencies, we have got a field office out there, we have got pumpers, people on the ground, it is the same technical team, so it really helps economically.

Great, thank you very much.

Thank you.

Our next question comes from the line of Leo Mariani from RBC Capital Markets, please proceed with your questions.

Hey, guys I just wanted to see if you had any thoughts why the latest four wells in northeast Pennsylvania that averaged 22 million a day were so strong here?

Well, I think it is several things. I think our technical team is just getting better and betterat understanding the rock, and where to land the lateral, and just all of the things that go with that. And I think the rock is just phenomenal. Northeast Pennsylvania has probably got the best in my personal opinion, it is not a Range opinion, my personal opinion, the best dry gas rock in the world. There are some huge wells up there, and again those wells are only 3,000-foot lateral lengths. And with ten stages. There is no doubt that if we were drilling 5,000 or 6,000-foot laterals those wells would be incredible.

So I think that it is just a combination of all those things, but again, it is primarily just the rock. The rock rules and understanding that opportunity, and how best to capture it is just a real testament to our technical team. We took a really experienced technical team out of the Barnett, and we assigned that project to them a year and a half ago or so, and they have literally gone from essentially zero to where they are at today. Bringing on wells, those four wells is just an unbelievable amount of volume. That was almost where we were at in the Barnett, after four or five years. So it is pretty phenomenal to see that happen.

Yes, I think just factor that simple comment, not only do you need to be in the right place, but you need to be in the right part of the right place, in the core area. So we have a huge position, and really dominate the wet part of it, or super rich where the economics are strong, but even in the dry, we have some of the best acreage out there. Coupled with the first class technical team working it. And a pretty good Chief Operating Officer too. (Laughter)

And a great CEO.

Did you guys use RCS on those wells, and what was the cost associated? Is.

We did not use RCS on those wells.

There is upside in terms of like Ray said, longer laterals, more stages, RCS, can we land them in even a better spot, all of those types of things.

What do those cost you to drill?

Those wells, they would be right in line with what you see in the investor presentation. I have got so many numbers in my head, I can't call it off the top of my head.

6.2 on the long.

Yes these were like 3,000-foot laterals.

So you are probably ballpark-ish five.

5.5. 5 to 5.5 I would guess.

The economics are right on the website like Ray said.

Yes.

Okay, and I guess just looking at southwest Pennsylvania, you talked about capacity constraints there. And can you give us more color on what you are doing to address that?

I am sorry say that question one more time?

Can you give us more color on what you guys are doing to address capacity constraints in southwest Pennsylvania?

The capacity constraints that I was talking about on that one particular pad. By the way, let me retract on the 2,600-foot laterals with nine stages are $4.3 million. So we were probably just a little above that actually, on those particular four wells we were just talking about. But the capacity constraints in southwest PA that I was referring to on that one example, I was talking about in my prepared remarks, that was really associated with that one pad. We just really never anticipated that strong of wells coming out of one pad. So they had not put enough compression capacity there to handle that. That is what it was.

So essentially the guys added some more equipment, piped some things up to different ways, put some more separation equipment online. That sort of thing. And that got us going forward. Overall in southwest PA we are in great shape. Mark West has just done a fabulous job. Of course, there are certain things that we would like to have faster, and certain things that they would like for us not to change our minds so often. But to make a long story short, they have done a great job, they are out in front of us, and the most important thing I can say to you is we are well on track to meet our goals this year. Way don't see any issues on the infrastructure side that will keep us from getting there.

That is great. What are your well costs right now in southwest PA on average in the different areas?

The straightaway laterals, just like we have got in the investor presentation are running about $4 million. Of course, we are working on longer laterals, we are also working on the RCS completions. Putting more frac stages in. So you will see those prices go up and down, as we incorporate those different techniques in the well designs. But the standard well today is about $4 million.

What is important is with the efficiency improvements that we are seeing and the reduced service pricing that we are recognizing in that area, we expect those prices to continue to go down, but as typical what the guys will figure out how to do is use the money that we are saving to invest back in more wells, more frac stages, and more perforation clusters, or all of those things. And again, all of that we have seen them, you have seen what they have done over the last couple of years, and they just continue to get better and better return on investments, and that is what it is all about.

Yes, and just referring again to the presentation, you can go online and look at it. We give you a couple of examples. A straightaway well down there, that is about a 3,000-foot lateral in ten stages it is about $4 million. And then in the super rich example, which was the average of the eight, they were about 3,700-foot laterals with 14 stages, and they are about $4.7 million. But like Ray said, how we complete the well will dictate what the cost is. But the good news even if we go towards longer laterals, reduced cluster, and higher wall costs, we are doing that because it generates higher rates of return.

Thanks, guys.

Thank you.

Our next question comes from the line of Joe Magner from Macquarie, please proceed with your question.

Good afternoon, thanks. We recently saw you all do a farm out transaction of some acreage in the east Texas Eaglebine play. Is that something that we might see more of in the future? And if you could give us a update on your appetite or interest in JVtransactions, as you look to accelerate or optimize developments some of what might not be near term priorities for Range?

Yes, I think if you stand back and look at us we have been pretty open minded with what to do with our assets. To start with, from 2004 through 2011, we sold $1.8 billion worth of properties, the biggest piece because the Barnett for $900 million we did roughly a year ago. And like Ray said, importantly through our technical teams and the robustness of our portfolio, we basically made the production up by the end of last year. We are open minded of what to do. The example you gave, we have properties down in Walker County, we had identified an opportunity, got out in front of the pack, leased some acreage, and probably all-in for under $200 an acre or less. When we drilled one well on it, we were never able to put together a sizable position in the play, and it ended up being fairly deep and fairly expensive wells. When you stand back and look at it, before we did the deal, it was an area we were never going to fund probably. So what we did is we farmed it out. Kept the 25% interest, we have a carry through tanks. We have an override across the entire position, and that is more important to somebody else than it is to us right now. Just like the Barnett, got to the point in our portfolio, if you go back to 2006, 2007, 2008, it was a big driver, but it got to the point last year that we never were going to fund it, the rates of return were so much better in the other area, we weren't going to get to it, so we have been very open minded in terms of farm-outs. Selling properties and whatever we think maximizes our share price.

Okay. And would JVs be of interest in the past, there has been some reluctance to enter into those types of transactions?

Yes, I think again, it is just a matter where the opportunity is. To the extent we think things like that make sense, we would consider it. So far we haven't seen an opportunity that we think is the right thing to do.

Thanks. And just any updates on spacing assumptions? Any of your sort of top five plays with discussions around increased lateral lengths, and changes to some of the completion designs? I think on the last call, you provided kind of a run down of at least near term spacing assumptions. Just curious how you are looking to make any changes or tests? Any down spacing opportunities?

I think that is a really good question, and it has far reaching implications, and I will walk through some of the areas. If you start with the Marcellus, we are basically drilling the Marcellus on 80 acre spacing. When you look at the resource potential numbers in there as large the numbers are, two things I would like to point out. A lot of the acreage is derisk, in the southwest you have got over 90% of the acreage derisked from over 1400 wells, and back to our discovery well for the play, production came on in 2005. So you have got seven years, up to seven years worth of history on 1,400 wells. We are drilling them on 80-acre spacing, and we put a couple of pilots in on 40-acre spacing down there a couple of years ago. So we have got plenty of data.

When you look at the resource numbers that are in there, in aggregate they are probably assuming in the Marcellus, roughly a 30% recovery factor, plus or minus. I would argue if you look at that, when you look at the recovery factor, it is going to come down to the quality of rock and the spacing that you drill on, and the efficiency of the completions. If you use the Barnett, which is the oldest of these types of shale fields as an analogy, in the best parts, in the core parts of the Barnett, people have drilled it down to as tight as 20-acre spacing, granted it is thicker, but they drilled it down to as low as 20s, . and got recovery factors on the order of 50%.

We are at 80-acre spacing it isn't unreasonable to think at some point in time you couldn't go to 40s, and that our recoveries could double, or we could drive through tighter spacing, better completions and all of that type of thing. Recovery is up into the 50% range. That is an enormous upside, given the amount of acreage we have, and it is in one in the high rate of return plays in the US. Tremendous upside, so I am excited about that.

If you go to the horizontal Mississippi, and again on our website we talk about the first eight wells Ray just updated you with two more. And they are actually performing better than the first eight. As we get more data, we will eventually update the curves like we have everywhere else. If you look at that slide, those first eight wells averaged 485,000 BOEs at a depth of 4,200 feet. At strip pricing that is a rate of return of 86% to 99%. Tremendous rates of return, but under that current completion, it equates to a recovery of about 4% to 9% of the oil in place. And assuming we kept those laterals, it is about 55-acre spacing. So do I think and this is oil not gas.

So in oil, typically it is more viscous fluid, you can drill in tighter spacing. You have got a lot of oil in place. I think it isn't inconceivable in an oil play to maybe even drill tighter and to double recoveries. Maybe 4% to 9% becomes 8% to 18%. And then I think when you stand back and look at that again, enormous implications. We have 145,000 acres if you use spacing like that, you could be talking about something as high as 2,800 wells, plus or minus 2,700 or 2,800 wells, and then if you use 0.5 million barrels per well equivalent, you are talking about over 1 billion barrels net to range, if you double it through tighter spacing you generate some enormous numbers. We aren't that big of a company. Again high rate of return play, really strong technical team, stack pay area, so your spacing question is a good one, and then you can take that into the Cline or the Wolfberry or other areas. Anyway, I will just stop there. It is very exciting upside, but we really aren't touting much. Good

Alright, thank you for that.

Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Please proceed with your question.

Thank you, good afternoon, gentlemen.

Hello, Dan.

Can you review for me the targeted economics of the vertical Wolfberry? Just the recoveries and the drill and complete costs?

Currently, the vertical Wolfberry wells at about $2.8 millions. The technical guys believe they can get that down significantly to 2.4 million range pretty quick. What we are reluctant to talk about yet is the EUR of those wells. It is just simply too early, we are definitely excited about it. They compare favorably to the offset operators, but that kind of gives you a flavor for what we are doing. And again, our plans to drill two more of those across the summer here, we will drill one. We will go drill three of the horizontal Cline wells and then back and drill the second addition to the vertical Wolfberry well. But they are completed 11 to 12 stages. Again they are vertical. So that gives you a framework of what we are looking at.

We also gave you the 24 hour rates to sales. We gave you the 90-day rate on the older well, if you compare that, it is only a 2-well data set, with not a lot of history, but it looks good. Right now it looks very encouraging. But rather that put reserves up, we would rather see at least another quarter's worth of data, before we put it out. But so far it looks great.

Got it. And then turning to northeast PA, how much of the 180,000 net acres is held by production today? What is the expiry schedule look like, I guess over the next 12 to 18 months or so? And what is the capital commitment involved?

We are really in good shape. If you got on the website, it will show you this, about 51% HBPcurrently. And those are big leases up there, we feel, and what they have on them are continuous drilling clauses. I always use the example of our biggest lease is on 20,000 acres or more, and literally you control one well per year, and hold it forever as long as you do that. And most of the leases are 1,000, 2,000, 6,000 acres. So 1 to 1.5 rigs will hold all of the acreage that we want to hold. Which is the core part of it. We are really in pretty good shape there. Really, if you think, if you step back even farther, and look at what do we need to drill to hold. What we really need to drill to hold is southwest PA, in the wet, and in the super rich. Southwest PA in the dry is held by legacy historical production, either from the upper Devonian or Riskani or wherever, so the dry part is pretty much held down there. Where we need to drill to hold is wet and super rich Marcellus and the horizontal Mississippian. And it also happens to be where our highest rate of return projects are. So fortunately we are blessed and those are lined up. That is where we would spend our money anyway, because those are our best rates of return.

And I will just add on, drilling in southwest P.A. when we drill the Marcellus well, we are actually holding the acreage for the upper Devonian and the Utica below that. So we HBP everything when we drill a well those.

Yes, any of these wells to any depths holds all horizons, and obviously the value in the Utica we think is going to be in the wet up in the northwest. We will be testing that this summer, down the road I can't tell you whether it is X years, but there is tremendous dry gas reserves underneath all of that stuff down in the southwest. A lot of that acreage is prospective for dry Utica. That some day will be worth a lot.

Yes, we don't have any of that dry Utica in any of our numbers anywhere.

Right.

Nor do we have any of the wet Utica.

Yes, we don't have any Utica.

Not in any of our resource numbers that we are have released publicly.

What was the price tag the banks applied in this latest redetermination?

It starts at about 275 for 2012. That is the agent's deck, and it escalates from that. We will probably see some adjustments to that later this year. They roll forward your first slug of production through the next redetermination date. A lot of that 2012 price wasn't really germane.

Right. And can you speak or to maybe even give some guidance on what the ratio of long term debt to EBITDAX might look like over the balance of this year or 2013? What is your comfort level or your discomfort level?

Yes, Dan, we are comfortable basically 3 and under. It eeked up just over 3, to 3 times right before we sold the Barnett. So when you see it get up with a 3 on the front, we are usually working on something to get it back down. Right now it is about a 2.6, so I think you will see it hover around that 2.6 range for the rest of the year. Maybe a little higher, just depending on how things drill out.

Got it, thank you.

Our next question comes from the line of Neal Dingmann from SunTrust Robing Humphrey. Please proceed with your question.

Good afternoon, guys. Just a couple of quick questions. That phenomenal result, you talked about the 24 hour rate you were just reading on the700. And then obviously 1,500 if you include the condensate. Does that make you think ant changes the drilling schedule, anything for the remainder of the year? Or is there still just too much to define there.

Well, wells like that is what actually started making us change our drilling schedule a while back. The drilling schedule is continually getting optimized, and what we are trying to do, like we do in all our areas is again, especially in this environment is critical just to try to get the best return wells that we can drill. So every time we find wells like this, we will immediately look for offsets, and look for opportunities, and try to figure out how we can duplicate that as many times as possible. And if we have the ability to shift a lower rate of return well, that was maybe not as rich, or something like that back into this area, we would certainly do that throughout the year. But as we go further, your ability to change anything that is going to impact production this year becomes less and less, just simply because we are a much bigger ship than we used to be, trying to turn and change directions very frequently. That is exactly what we are trying to do, is find more wells like that.

And it helps set up an exciting 2013.

If they do decide to ramp that up, there is enough capacity to do so?

You mean as far as infrastructure capacity? Yes, absolutely. We are well ahead on process, and capacity and all of the gathering and compression, it looks like the guys are continually working with the Mark West team on that. And we are well out in front, so we are in good shape there.

Okay. And then switching over to the Utica, what are you thinking as far as forecasting for well costs there?

I would just say that is way too early. The guys are still working on the design of the initial well. We will get all of that and we will put that out.

We will do some science of course too which would not be normal, on this first well.

It is a really exciting opportunity, it is at the right depth, right thermal maturity, and a big 190,000-acre blocking position that should be in the wet and condensate area.

One last--, go ahead.

I was just going to say, more confirmation, there are a lot of knowledgeable people all around us up there, so we are at the point where we are just left with the decision, we just have to drill some wells now and see what we have got.

Yes. And the same thing, we have a great team on the ground, we have a field office that is a historical producing area for us, so we are in good shape.

Okay. Last one, turn it over to the horizontal mist, just wondering it does sound like the latter part of the year, you anticipate ramping the number of wells there, just looking at the water disposal, how is that is addressed, or how you see the costs for that going forward?

We today the horizontal producers are about $2.9 million, and that is actually what they are spending today. We are allocating about $200,000 a wellfor saltwater disposal, and that can run, between eight, one well can handle between eight to 12 wells, and I think only time will tell as we ramp that project up. But we have got a great disposal zone. We have great infrastructure. We have been very disciplined in our leasing program to try to stay very consolidated, and what we know about that play is it, operating cost is really going to be a key thing there. So we have really been disciplined, and I think at this point, the salt water disposal infrastructure is coming together nicely. We don't see any issues, but of course, we only have got our first two wells on line. We will be watching that real closely, and certainly as we get towards the end of the year and into next year, you will see that ramp up significantly.

Perfect, thanks for the color.

Okay.

Thank you.

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

Just a couple of quick questions. When will your acreage in southwest PA, the wet and super rich be held by production?

We should, our plan is over the next three to five years, we will get there. A big portion of the leasing capital that we have in our $1.6 billion budget goes to southwest PA. And it is just simply filling in holes, and blocking up what I call blocking and tackling as we are drilling through that area. So it is hard to talk about absolute black and white numbers when things will be HBP, because we will be continually adding new leases as we get opportunities to bolt on. We should substantially have all of that done in the next three to five years.

Okay, thank you. And in terms of the new improved completion techniques, and lateral placement designs this year, what percentage of the wells that you are drilling this year in the wet and super rich, would you say are going to use those new improved techniques versus old techniques?

That is a great question, Marshall, and to be just flat honest with you, I don't have that answer yet. Give me another quarter, and I think we'll have those plans locked down, what the team is physically doing today, is going through and just seeing how much of that we can add into this year's program. Because like we talked about earlier, every time we do more of that, it does cost more money. So we are going to stay within our $1.6 billion capital budget, and we absolutely are not going to spend more than that, so it is really a juggling act of where does it make sense to do it. It is certainly not at the point where we can say it just blanket makes sense to do it everywhere we go. But we will be doing enough of it, or let me say it another way, we will be doing as much of it as we can. And I think in probably another quarter I can give you a range or a percentage of wells that we will be doing those techniques on.

And I think the key again, remembering, the old techniques in the wet area where three years and almost 200 wells generate about a 75% rate of return, which is pretty exciting. And in the wet area, based on those first eight, it is about 95%. These are enhancements to that. I think what you will see in time, into 2013, 2014, 2015, like what Ray said, you will going to see I think continuing improvement.

Yes, let me add even more to that, we are also taking what we are learning there in the Marcellus, and we are actually talking to the Oklahoma City division office about it, and even the west Texas guys. And seeing if any of those techniques makes sense to try in the oil plays in the horizontal Mississippi or the Cline.

Yes, and remember in the Cline, we are two wells into it on 100,000 net acres.

Alright, thank you. Great job.

Thank you.

We are nearing the end of today's conference, we will go to Mike Scialla from Stifel Nicolaus for our final question, please proceed with your question.

Hi, guys. I think you said you had seven rigs running in the super rich area, and how many total do you have in southwest PA now?

Today there are nine rigs total running in southwest PA.

So are those two that are in the wet area I presume, is that kind of a good run rate to hold that area going forward? And you will continue to concentrate on the super rich?

It is going to go up and down, Mike. I don't have those averages because just like what we where are talking about a little while ago, as we are gaining, as these new wells are coming on line, and starting to figure out what the potential is, you have to look at things like HPB, you have to look at infrastructure and development, and where does it make sense to change our plans and move rigs from the wet to the super rich. You will see that go up and down quarter to quarter. We may have more rigs running in the wet area for a quarter than we do in the super rich going forward. It is just going to ebb and flow, so I don't think you can hold that flat, I think the only thing you can hold sort of flat would be in that 7 to 9 rig range throughout the yearin southwest PA.

Okay, and then along those same lines, if I look at the resource potential numbers you guys put out there, it looks like you expect the upper Devonian to have a higher liquids content than the Marcellus, kind of looks like 300 barrels per million versus 200 barrels per million. One I guess am I reading that right? And if that is right, is there a chance we can see a shift more emphasis towards the upper Devonian going forward?

Well, I think it is apples and oranges. Because the Marcellus is the entire MarcellusWhich is all of the dry acreage and northeast PA, and along with the dry acreage in southwest PA, plus the wet and super rich areas. The upper Devonian is really concentrated to the wet and super rich areas. And we really don't have much of the upgrade in either for the super rich type stuff. We simply have got to see some more results before we go that far.

And it is so early in the upper Devonian and the recovery factors we are using there are significantly less, so until we get more data, what we will do is continually update it with time.

Makes sense, thank you very much.

Thank you.

That comes to the end of our Q&A session, I would like to turn the call back over to Mr. Ventura for closing comments.

Before I give my closing comments I would like to note that we have several more questioners on line that we weren't able to get to, so I would encouraging you to give us a call, and we want to make sure to follow up and answer your questions, along with anybody else that might have some. Make sure to do that. But for the closing comments, I would like to close with what I believe are the four main take-aways for Range. First, we have a very large acreage position in some of the best plays in the country, given the acreage we have, we should be able to achieve double-digit growth in production and reserves on a per share basis debt adjusted for many years. Second, given the high quality of our acreage, and the plays that we are in, we should continue to be one of the lowest cost producers in our peer group. Third, as Roger just discussed, we have significantly strengthened our financial position, and are in a solid position to fund our capital program. Finally, the five enhancements to our portfolio, the super rich Marcellus, the super rich upper Devonian, the wet Utica, the horizontal Mississippian oil play, and the Cline Shale oil play, all offer significant upside to the Range story. Additional news on all these plays will be coming on our second, third, and fourth quarter calls. Thank you for participating on the call. I believe these four keys will drive shareholder value for years to come. Thank you very much for participating on the call.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.