Range Resources Corporation (RRC) Q1 2012 Earnings Report, Transcript and Summary

Welcome to the Range Resources First Quarter 2012 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that are not historical facts are statements forward-looking. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions] At this time, I'd 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 decrease in unit cost. 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-Q with the SEC yesterday. It's now available on the homepage of our website or you can access it using the EDGAR system. In addition, we 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 modeling 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. Now let me turn the call over to Jeff.

Thank you, Rodney. I'll 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'll open it up for Q&A. Range is on track to achieve the targets that we've set for 2012. We're 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're also making good progress in all 5 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 5 projects in his talk. Financially, we're 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 company's 5 largest cost categories fell by 6% in aggregate compared to the prior-year period. Our natural gas hedge position is excellent for 2012. We're 75% hedged to the 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 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 on 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'll be decreasing our rig count in the Northeast to roughly 1 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's now not only important to be in the core part, but you've got to be in the wet core. Also, not all 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 at one of the best rate of return plays in the U.S., which is the 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 rate of return plays in the U.S. Plus, we have tremendous upside in the super-rich and wet Upper Devonian, wet Utica and the Cline Shale oil play. Including only our 5 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 and reserves per share on a debt-adjusted basis for years to come, with strong returns and low cost even in today's commodity price environment. We'll 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's great feedback to hear in any environment, and we're proud to have earned that trust. I'll turn the call over to Ray to discuss operations.

Thanks, Jeff. My comments today will cover several topics. I'll talk about cost, efficiencies, well performance, production guidance and give some operations updates from our divisions. Like Jeff said, we're off to an excellent start to meet our production growth targets in 2012. Our plan to shift more of our resources and capital investment to liquids-rich and oil projects is on schedule, and we can see this already beginning to pay off. As we stated in our earnings release, the first quarter production came in at 655-point (sic) [655.5] 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 condensates. I think it's 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're getting 3.2x the realized price for our wet gas versus 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've completed the majority of our HBP drilling 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 gross 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's basically a result of timing for new wells and infrastructure coming online throughout the year. These fluctuations are simply necessary for all the advanced planning for our drilling program and infrastructure development that is underway. In the Marcellus, we brought online some great wells in the first quarter. For example, sales from the 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 2 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 3 of those 10 wells. This flow period lasted about 28 days. After changing equipment at the compressor station, production from the same pad was ramped up to approximately 75 million per day. This rate has been steady for 4 days. And at present, a total of 7 wells out of the 10 wells are producing, with the other 3 wells still setting in as we are still capacity-constrained to 75 million. The average lateral length for these wells is 2,763 feet with an average of 10 frac stages each. And none of the wells have reduced cluster spacing completions. Again, reduced cluster spacing is simply a technique utilizing clusters of perforations that are placed closer together on the lateral. I'll refer to the reduced cluster spacing technique as RCS throughout the rest of my remarks. This 10-well pad in the wet area of the Marcellus was 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 in capital efficiency and well performance going forward. Shifting to Northeast Pennsylvania. In Lycoming County, we recently brought online 4 new horizontal wells that produce the sales at 24 IPs, up 26 million, 23 million, 21 million and 18 million a day, respectively. Those wells had an average lateral length of 3,000 foot and 10 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'll decrease activity to the 1 to 1.5 rig level at year end as we HBP 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 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 LOE in just a few minutes. As important as making improvements in cost and well performance, we are also making great improvements in operational efficiency. 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's 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 a result of our key performance indicator process which focuses on equipment and location personnel. It simply utilizes GAAP identification to identify opportunities to work faster and smarter. This 53% improvement in frac efficiency translates to a 12% composite average of savings in our overall completion cost. We're also seeing very good improvement in service pricing. As an example, recently renegotiated frac contracts are expected to translate to a 4% to 5% improvement in total well cost and will literally save us millions 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 3, 2012 super-rich Marcellus wells. And while it's 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 the 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 is 2,752 feet, 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've opened it up. I just got a report this morning and for the last 24 hours, the well made 168 barrels of condensate, 578 barrels of NGLs and 8.1 million of gas. That's almost 750 barrels of liquids not counting ethane. If we counted ethane, it would be 1,547 barrels of liquids with 7 million cubic feet of gas. This well certainly bodes well for the super-rich area 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 7 rigs running in 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 3 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're just getting started in the super-rich Upper Devonian Shale and have now frac-ed our first well and are literally commencing flowback operations as we speak. We're also currently drilling the second well. We have rotary sidewall cores in 2 super-rich Upper Devonian wells. And although we've not completed these wells yet, I'll give you some preliminary observations. We see TOCs of up to 11%, cross fees up to 8% and permeability measuring all the way up to 700 nanodarcies. 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 loss shows [ph] that we've seen today across any Upper Devonian Shale. Now here's 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 2 rigs running and have brought online our first 2 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 and 15 stages with 100% working interest and 81.5% NRIs. We've also increased our acreage position to about 145,000 net acres. As it's still early in this play, and as we continue to closely watch our results, it's part of our overall goal to continue to shift our focus towards a very high rate of return projects across the company, and this is surely one of those. The infrastructure, both midstream and saltwater disposal, were 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 Northwest PA. Namely, 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 to offset operators that are all confirmation of a potential liquids-rich play. Proprietary log and core data that we've recently obtained continues to support that this area is highly perspective for liquids-rich and condensate production. We feel our 190,000 net acres, which is primarily HBP-ed, is positioned well and we're 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'll be moving a rig in this quarter to begin drilling 3 wells across that acreage. Devon has permitted 3 wells, directly offsetting our lease line to the East, 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 area have 4 rigs running. The IP of the second Cline well was 484 BOE per day, with 282 barrels of oil, 123 barrels of NGLs and 476 mcf of gas. And it was completed with 11 and 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 7 of 10 stages successfully completed. As you can tell, we're 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 lengths, different completion designs, we believe our technical team can significantly improve results going forward. All of this information will be helpful in derisking our 100,000 net acre position which, again, is 90% HBP. 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 lengths 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 team has continued to do an outstanding job with their legacy stock-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 stacked 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 could certainly see that same potential here. As confirmation of the potential here, I'll also point out, that there are 33 rigs in the area drilling Wolfberry wells. We plan to drill 2 additional vertical Wolfberry wells this summer, while we have the rig out there drilling the Cline wells. We'll drill one vertical Wolfberry then the 3 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 and 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'm also really proud of their progress in the areas of safety and environmental protection. We continue to make improvements in handling our fluids across all of our operations. For 2011, our spill rate when handling produced water, flowback water or oil and condensate was 0.0025%, or more simply said, 25/10000 of 1%. While still not 0, which is our constant goal, this is indeed an accomplishment to be proud of. In fact, we've 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 the 0 spills going forward. At the same time, we achieved a 50% reduction in recordable incidents during the first quarter, along with a 60% reduction in days-away restricted and transferred instance, or what we used to call loss-time incidents. Our total recordable incident rate was a 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're 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'll start with the balance sheet and then work over to the income statement. Range strengthened its balance sheet in the first quarter through 3 actions, designed to bolster liquidity and reduce risk. First, in February we issued $600 million of 5%, 10.5-year, no co-fi [ph] 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 helped 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 3 new North American banks to the credit facility. The addition of the 3 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 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. EBITDAX 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. The earnings calculated using analyst methodology were $24 million or $0.15 per share, that's $0.02 above analyst consensus estimates. Our website contains full reconciliations for 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're pleased to report another quarter of reduced unit cost expenses. Direct operating cost, 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 cost, low service cost and equipment rentals. Operating cost also benefited from unseasonably mild winter weather. We expect unit cost 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 a separate line item as opposed to netting the expense against revenue. On a unit cost basis, transportation gathering and compression expense was $0.68 in the first quarter, up from $0.56 last year. It came in slightly over guidance on this item in the first quarter due to some prior-period adjustments. Second quarter expenses should be approximately $0.63 per mcfe. The DD&A rate for the first quarter was $1.68 an mcfe, that's $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 reevaluate our proven reserves. The first quarter marks the debut of the Pennsylvania impact fee, which we are combining with the production tax and as one 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's 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'll be providing quarterly guidance for the Pennsylvania impact fee on an absolute 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's also a $6.2 million current year impact fee provision representing the first quarter accrual for wells drilled so far in 2012 and the carryover 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 cost in the current closing 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's up $3 million from last 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 swap additional 2013 natural gas volumes during the quarter, bringing our 2013 natural gas hedged 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 a 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 we'll see a front loading of capital spending, while the back half of 2012, we'll 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 our marks on the operating side. Jeff, back over to you.

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

[Operator Instructions] Our first question comes from the line of Brian Singer from Goldman Sachs. Mr. Singer, are you there? [Technical Difficulty] Our next question comes from the line of Pearce Hammond from Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: You spent $75 million on land this quarter. Is that onetime in nature? Or could that bias total CapEx higher throughout the year? And then how is that allocated? Was that all in the misc line?

No, on capital, we're confident we'll stick to the $1.6 billion for the year. So we'll be at that number, along with the 30% to 35% production growth and 40% increase in liquids. So we're on track there. That 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's where we're spending all of our money. Pearce W. Hammond - Simmons & Company International, Research Division: 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 in that play compete with some of your other areas?

Yes, I mean, it's been good news. The team did a really good job of coming up with an opportunity. And I'm going to step back for a minute, I think a lot of what you see, it's typical across our areas. We get in the areas that have stacked pays, rich hydrocarbon charge and really good technical teams working in those areas. And what that allows is for opportunities year after year after year, because those guys figure out new things and new ways to increase recovery factor. So that's very typical of the Range portfolio. It's a great opportunity, the wells are performing strongly. In fact, if you compare them against other operators and other analogous production out there you'll see -- granted it's just the first 2 wells, but they compare very favorably. The rates of return looks strong. We were actually debating whether to do more on this call and decided to wait maybe another quarter, maybe do them on the second quarter, but they're strong rates of return. We'll drill a couple more wells this year. Like Ray said, it's an exciting opportunity, 100 to 150 locations at 40-acre spacing. I feel comfortable in time, it's probably more likely will be double that because it's more likely 20s or lower spacing, given the fixed section and high amount of hydrocarbon in place. But I think we'll stay on track. That's an exciting opportunity, but the Cline is equally exciting in that the Cline covers the entire 100,000-acre position. At 50-acre spacing, that's potentially 2,000 wells. And you can see knowledgeable Permian players all around us are 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. Pearce W. Hammond - Simmons & Company International, Research Division: And then one final question, which is 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 that are leading to that?

Yes, and that's a good question. Basically, it's just an artifact of wells coming online and timing with the infrastructure that's being planned. I mean, like we talked about in the last quarter, a lot of these projects we've 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 is just an artifact of the point that even though we're bringing out some of the new horizontal Mississippian oil wells, they're just not coming online. And we're just not going to see a lot of that 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've got in the wet and super-rich Marcellus area. And that stuff is just simply artifact of the wells coming online. So what you're seeing is the wells are going online in the first quarter just naturally declining off, and we're just not adding that many wells in the second quarter.

The important point though is we're still on track for 40% year-over-year growth.

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

Couple of questions. First, on the -- with regards to your reduced cluster spacing, can you just talk about how widely you expect to use that across your Marcellus acreage? And then what that does in terms of well cost relative to your standard completion?

Great question, Brian. The reduced cluster spacing is a technique -- it's really 1 of 4 different things that we're working on right now. There's reduced cluster spacing. There's going to moderately longer laterals. There's increased conductivity frac designs, which is simply putting more higher conductivity fractures that potentially could be smaller jobs pumped and then better targeting of the lateral in the rock. And so it's -- we very seldom, as much as we would want to, just try one of those things at a time. You really -- never really get that opportunity to do that. So it's really hard to say that a certain amount of cost increase is associated with RCS versus smaller frac jobs because we'll be combining all of those going forward. And the answer is yes, it does cost more to put the perforations closer together because we're doing more of it. And it does cost more to do more frac jobs along the lateral. And in some cases, if we're steering the well a little more, it may cost more to steer the well while we're drilling. But what we're 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 those various combinations. And with the -- we got 7 rigs running in the super-rich today, we'll be adding a lot of data to analyze over the next coming months and quarters. So I think, really, we'll have a good feel for how all of those things affect our results going forward. But the important thing is everything we've done today says that we're getting better results. But I'm reluctant at this point because it's so early to tell you that a certain amount is attributed to RCS versus lower laterals or whatever else we're doing.

I'd 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 and wet Marcellus under strip pricing or what's out there on the website, that generates a 73% rate of return. And we're -- the actual economics, and that doesn't incorporate all the things that Ray are saying. So there's a chance as good as 70% -- 73% is that can get better. Same thing when we announced the 8 wells in the super-rich originally, and that's the economics set on our website that you can look at. They're actually even better. They went up to a 95% rate of return at the strip pricing that's on the slide there. But there's a chance you can enhance that because we did not apply all 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.

And do you expect that -- given that these wells are producing at twice the initial rates, do you expect a normal course decline curve that would 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's just too early to know. IPs are not necessarily as good a judge of the character of the wells' performance long term. It's what they used to be in the old days because -- one simple reason certainly in the Marcellus is, there's very few wells that ever come online that aren't constrained somewhat due to compression or gathering or whatever. So the answer is we're 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're trying we believe will drive those returns that we've got in our investor presentation up even higher. And that's what we're really shooting for.

And another key thing there. When you look at those economics like I just referred to, in the super-rich, we have the 8 wells originally that we announced on the last call where I gave you a little more color this time. But those original 8 wells have been online for an average about 1.5 years. So those aren't 24-hour IPs or 7-day or 30-day. That's 1.5 years worth of data.

And then very quickly, in Bradford County where you've got the non-operator position, is that the acreage that's held by production? Or do you see any acreage exploration issues given the lack of drilling because of pricing?

Yes, one I'd like to point out, that whole position is about 14,000 acres. So it's really small, it's relative to the over 1 million acres net that we have in the state. It's a tiny, tiny fraction. And a lot of it's held -- maybe a little bit of the 14,000 goes away. Now that's in the dry gas area and they've actually gone down to 0 rigs in that area.

Our next question comes from the line of Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Ray, just a quick follow-up on Brian's question on the RCS. Can you give us a sense in terms of what -- how many more clusters are you doing per stage under the RCS method versus your prior method?

Well, I don't know that we're locked into a specific spacing between clusters yet. But I can tell you, I think most of the recent stuff we're doing is we've gone from 3 clusters -- originally in our completions we were 3 clusters spaced 100 feet between. Basically, 3 clusters in a 300-foot interval. Now we are 3 clusters in a 200-foot interval. But that could change. We've experimented, I think, all the way down to 150 and we've actually even got longer than 300, again trying to figure out what the optimum is. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And from a lateral placement, can you talk about what you're doing differently and add a little bit -- maybe provide a little bit more color on what the analysis suggested in terms of why you're changing the placement of the lateral? And how much of an impact do you think that the simple lateral placement could have on the EURs or well performance?

Well, I think, being a guy that's frac-ed a bunch of wells in my career, a year or so ago, what I said, it wouldn't make any difference where you land the lateral because we're going to bust it all up when we frac it. But today, I'll 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 do 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's 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. So we're 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 wet to the other side of the super-rich is -- that's an hour drive in a car. So it's a big area and it's going to change a lot. What's critical is, just like Jeff talked about earlier in his remarks, is 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. And I fully expect that we'll keep seeing improvements going forward. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: 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 this -- that the Wolfberry portion of the play is combined to the Western portion of your Conger field?

That's exactly right. That is fair.

That's why we gave you a well count rather than acreage. We think it's 100 to 150 at 40s and obviously, 200 to 300 at 20s. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Indeed. Do you think there's something going on as you're at that eastern portion of the basin that's different than what the industry has been doing in -- whether it's 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've only done a handful of wells. And so I would hazard to say that we're any better than anybody else. But I do -- it's probably more of the rocks than anything else right there. But again, like Jeff said, that's why we put the well count out there. It's not huge, but it's definitely significant and it's 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 us some great rate of returns. It's a great way to ramp up some oil production and we're excited. Once we get in there drill a couple of more wells, I think we'll have a great opportunity going forward to really ramp up some oil production there.

Yes, to me there's 2 things that are exciting. Regardless of the reason, I'm always excited when our wells are performing really well. And like Ray said, initially, it's 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's not going really to drive our reserves or resource potential but it can really significantly drive our oil production over the next 1 year or 2 or 3 or 4. And that's the exciting part about it is more high-rate opportunities are really working in today's environment. Plus it's, in essence, free acreage. It's back to having stacked pays high-quality technical team. It's nothing we acquired. It's something we had. And then you got all the efficiencies. We've got a field office out there. We've got pumpers, people on the ground. It's the same technical team, so it really helps economically.

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

I'm just wanting to see if you had any thoughts why the latest 4 wells of Northeast Pennsylvania and average 22 million a day were so still strong here?

Well, I think our -- I think it's several things. I think our technical team is just getting better and better at 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. I mean Northeast Pennsylvania has probably got the best, in my personal opinion, it's not a Range opinion, my personal opinion, the best dry gas rock in the world. I mean, there's some huge wells up there. And again, those wells are only 3,000-foot lateral lengths and with 10 stages. If you -- there's no doubt that if we were drilling 5,000- or 6,000-foot laterals, I mean, those wells will be incredible. So I think that it's just a combination of all those things. But again, it's primarily just a rock. The rock rules, and understanding that opportunity and how best to capture it is 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 1.5 years ago or so. And they've literally gone from essentially 0 to where they're at today, bringing on wells. Those 4 wells is just unbelievable amount of volume. That was almost where we were at the Barnett after 4 or 5 years. So it's pretty phenomenal to see that happen.

Yes, I think just a fact to that simple comment, not only 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've got 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've got, I think, some of the best acreage out there coupled with first-class technical team working it. And a pretty good Chief Operating Officer, too.

And a great CEO.

And did you guys use RCS on those wells? And what were the costs associated with those [indiscernible]

We did not use RCS on those wells.

So yes, there's upside in terms of, like Ray said, longer laterals, more stages, RCS, can we land them in an even better spot, all those types of things.

And what did those cost you to drill?

Those will also -- they'd be right in line with what you're see in the investor presentation. And as I got so many numbers in my head, I can't pull it off at the top of my head. But $6.2 million on a lot of them.

Yes, that means we're -- they were like 3,000-foot laterals. So you're probably ballpark-ish $5 million...

$5.5 million. $5 million to $5.5 million, I guess.

The economics are right on the website like we said.

Okay. And I guess just looking out South of Pennsylvania, you talked about capacity constraints there. And can you give us a little more color on what you guys are doing to address that?

I'm 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?

At Southwest Pennsylvania, look, the capacity strengths -- constraints that I was talking about on that one particular pad -- by the way, let me retract on the 2,600-foot laterals with 9 stages are $4.3 million. So we're probably just a little above that actually, on those particular oil wells that we're 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 wells coming out of one pad. So they had not put enough compression capacity there to handle that, and that's what it was. So essentially, the guys added some more equipment, piped some things up to different ways, put some more separation equipment online and that sort of thing. And that got us going forward. Overall in Southwest PA, we're in great shape. I mean, Mark West has just done a fabulous job. Of course, there's certain things that we'd like to have faster and certain things that they would like for us not to change our mind so often. But to make a long story short, they've done a great job, they're out in front of us. And the most important thing I can say to you is we're well on track to meet our goals this year. We don't see any issues in the infrastructure side that will keep us from getting there.

That's great. I guess, what are your well costs right now in Southwest PA on average in the different areas?

The straightaway laterals, just like we heard got in the investor presentation are running about $4 million. Of course, we are working on longer laterals, we're also working on the RCS completions. We're putting more frac stages in. So you're going to 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's important is, is with the efficiency improvements that we're seeing and the reduced service pricing that we're 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're 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've seen what they've done over the last couple of years and they just continue to get better and better return on investments. And that's what it's all about.

Yes and just referring again to the presentation, you can go online and look at it. And we give you a couple of examples, for like Ray said, say a straightaway well down there, it's about a 3,000-foot lateral in 10 stages, it's about $4 million. And then in the super-rich example, which was the average of the 8, they were about 3,700-foot laterals with 14 stages, and they're about $4.7 million. But like Ray said, that will -- how we complete the well will dictate what the cost is. But the good news, even if the cost -- if we go towards longer laterals reduce cost during higher well cost, we're doing that because it generates higher rates of return.

Our next question comes from the line of Joe Magner from Macquarie.

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 can give us an update on your appetite around or interest in JV transactions as you look to accelerate or optimize development some of what might not be near-term priorities for Range?

Yes, I think if you'd stand back and look at us, we've been pretty open-minded about what to do with our assets. To start with, from 2004 through 2011, we sold $1.8 billion worth of properties. The biggest piece of which last year was the Barnett for $900 million, and 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 out by the end of last year. We're open-minded on what to do. The example you gave, we had some 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 never were 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 fund it out, kept the 25% interest. We have a carry-through tanks, we have a override across the entire position. And that's more important to somebody else than it is to us right now. Just like the Barnett, it got to the point in our portfolio -- if you go back to 2006, '07 and '08, it was a big driver. But it got to the point last year, we never were going to fund it. The rates of return were so much better in the other areas, we weren't going to get to it. So we've 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's been some reluctance to look into those types of transactions, but is that going to change hereon?

I think, again, it's just a matter of what the opportunity is. So to the extent we think things like that make sense, we'd consider it. So far we haven't seen an opportunity that we think is the right thing to do, therefore we haven't done one.

Okay. And just any updates on spacing assumptions? Any of your sort of top 5 plays with discussions around increased lateral lengths and changes to some of the completion designs. Like on the last call, you provided kind of a rundown of at least near-term spacing assumptions. I'm just curious how you're looking to make any changes or tests, any down spacing opportunities?

I think that's a really good question and it has far-reaching implications, and I'll sort of walk through some of the areas. If you start with the Marcellus, we're basically drilling the Marcellus on 80-acre spacing. And when you look at the resource potential numbers in there, as large as the numbers are, 2 things I'd like to point out. A lot of our acreage is derisked. And in Southwest, you got over 90% of the acreage derisked from over 1,400 wells. And back to our discovery well for the play, production came on in 2005. So you got 7 years worth -- up to 7 years worth of history on 1,400 wells. We're 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 got a plenty of data. When you look at the resource numbers that are in there, in aggregate, they're 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 recovery factor, it's going to come down to the quality of rock and the spacing that you've drilled 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's thicker, but they drill it down to as low 20s and got recovery factors on the order of 50%. We're at 80-acre spacing, it's not unreasonable to think that 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 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's in one of the highest rate of return plays in the U.S., tremendous upside. So I'm excited about that. As you go to the horizontal Mississippian, and again on our website, we talked about the first 8 wells. Ray just updated you with 2 more. And they're actually performing better than the first 8. As we get more data eventually, we'll update the curves like we have everywhere else. If you look at that slide, those 8 wells -- even those first 8 wells averaged 485,000 BOEs at a depth of about 4,200 feet. At strip pricing, that's a rate of return of 86% to 99%, tremendous rates of return. With that, 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's a little -- it's about 55-acre spacing. So do I think -- and this is oil, not gas. So in oil, typically, it's more viscous fluid. You can drill on tighter spacing. You got a lot of oil in place. I think that it's not 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 a spacing like that, you could be talking about something as high as 2,800 wells, plus or minus 2,700, 2,800 wells. And then if you use 0.4 million, 0.5 million barrels per well equivalent, you're talking about over 1 billion barrels net of range. If you double it through tighter spacing, you generate some enormous numbers. We're not that big of a company. Again high rate of return play, really strong technical team, stacked pay area. So you're spacing question is a good one. And then you could take that into the Cline or the Wolfberry or other areas. But anyway, I'll just stop there. It's very exciting upside but we're really not counting much, so good question.

Our next question comes from the line of Dan McSpirit from BMO Capital Markets.

Can you review for me the targeted economics of the vertical Wolfberry, just the recoveries and the drilling complete costs?

Currently, what I did see in those wells, the vertical Wolfberry wells are at about $2.8 million. The technical guys believe they could get that down significantly to the $2.4 million range pretty quick. What we are reluctant to talk about yet is the EUR of those wells. It's just simply too early, and we're definitely excited about it. They compare favorably to the offset operators. But that kind of gives you a flavor for what we're doing. And again, our plan is to drill 2 more of those. Across the summer here, we'll drill one. We'll go drill 3 of the horizontal Cline wells and then back to drill a second to additional vertical Wolfberry well. But they're completed, 11 to 12 stages. Again, the vertical -- so that kind of gives you, I think, a framework of what we're looking at.

And we also -- we gave you the 24-hour rates of the sales, we gave you the 90-day rate on the older well. And if you compare that again, I mean it's only a 2-well data set and with not a lot of history. But it looks good. Right now, it looks very encouraging. But rather than put reserves, I 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's the expiry schedule look like, I guess, over the next 12, 18 months or so? And what's the capital commitment involved?

We're really in good shape. If you got on the website, it will show you there's about 51% HBP currently. And those are big leases up there. We feel -- and they have -- what they have on them are continuous drilling clauses. I always use the example of biggest leases, 20,000 acres or more. And literally, you can drill 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 the acreage that we want to hold, which is the core part of it. So we're really in pretty good shape there. Really, if you think -- if you step back even further and look at what do we need to drill the hold, what we really need to drill the 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, Oriskany [ph] or wherever. So the dry part is pretty much held down there. Where we need to drill the hold is wet and super-rich Marcellus and the horizontal Mississippian. It also happens to be where our highest rate of return projects are. So fortunately, we're blessed and those are lined up. That's where we'd spent our money anyway because those are our best rates of return.

Yes, and I'll just add on. Drilling in Southwest PA, when we drill the Marcellus though, we're actually holding the acreage for the Upper Devonian and the Utica below that. So we HBP everything when we drill a well there.

Yes, I knew these wells to any depth holds all horizons. And obviously, the value in the Utica, we think, is going to be in the wet up in the Northwest, and we'll be testing that this summer down the road. I can't tell you whether it's X years, but there's a tremendous dry gas reserves underneath all that stuff down in the Southwest. A lot of that acreage is prospective for dry Utica that at someday will be worth a lot.

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

Right, I got it.

Nor do we have any of the wet Utica.

That's true. We don't have any Utica.

Yes, none in any of our resource numbers that we've released publicly.

And then, what was the price deck the banks supplied in this latest redetermination?

It starts at about 275 for 2012. That's the agent's deck and it escalates from that. So obviously, we'll probably see some adjustments to that later this year. But they will forward your first slug of production to the next redetermination date. So a lot of that 2012 price wasn't really germane.

Right. And can you speak to or maybe you can give some guidance on what the ratio of long-term debt to EBITDA actually look like over the balance of this year to 2013. What's your comfort level or your discomfort level?

Yes, Dan, we're comfortable basically 3 and under. It eats up just over 3x right before we sold the Barnett. So when you see it get up with the 3 on the front, we are usually working on something to get it back down. Right now, it's at 2.6. So I think you'll see it kind of hover around that 2.6 range for the rest of the year, maybe a little higher, just depending on how things drill out.

Our next question comes from the line of Neil Dingmann from SunTrust Robinson Humphrey.

Just a couple of quick questions. After that phenomenal result, you talked about the 24-hour rate you're just reading on the 700 BOEs per day and then obviously the 1,500 if you include the condensate, does that make you at all think about changing the drilling schedule or anything for the remainder of the year, or is there still just too much to define there?

Well, you know, wells like that's what actually started making us change or grow the schedule a while back. The drill schedule is continually getting optimized. And what we're trying to do, like we do in all areas is again, especially in this environment, it's critical just to try to get the best return wells that we can drill. And so every time we find wells like this, we of course will immediately look for offsets and look for opportunities, 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's going to impact production this year becomes less and less, just simply because we're a much bigger ship than we used to be trying to turn and change directions very frequently. That's exactly what we're trying to do, is find more wells like that.

And it helps set up an exciting 2013.

Yes.

Well, would you all say you -- it does sound like there is, if you do decide to ramp that up even a bit latter part of this year, there is enough capacity to do so?

You mean as far as infrastructure capacity?

Correct.

Yes, absolutely. We are well ahead on process and capacity. And all of the gathering and compression, looks like it's -- I mean, we're -- the guys are continually working with the MarkWest team on that. And we're well out in front, so we're in good shape there.

Okay and then on -- switching over to Utica, what are you thinking as far as forecasting for well cost there?

I'd just say that's way too early. The guys are still working on the design of the initial well. But when we get all that, we'll put that out.

Yes, we're going to do some science, of course, too, which would not be normal on this first well.

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

I'm just going to say in more confirmation, there's just a lot of knowledgeable people all around us up there. So we're at the point where we just left with the decision. We just got to drill some wells now and see what we got.

Yes. And the same thing, we got a great team on the ground. We have a field office that's a historical producing area for us, so we're in good shape.

Okay. And then last one just turning over to the horizontal mix, just wondering, it does sound like in the latter part of the year, you anticipate ramping the number of wells there. Just looking at the water disposal, how is that addressed? Or kind of how you see the costs for that going forward?

We, today, are -- the horizontal producers are about $2.9 million. That's actually what they're spending today. We are allocating about $200,000 a well for saltwater disposal. And that could run between 8 -- one well can handle between 8 to 12 wells. And I think only time will tell as we ramp that project up. But we got a great disposal zone, we got a great infrastructure, we've been very disciplined in our leasing program to try to stay very consolidated. And what we know about that play is operating cost is really going to be a key thing there, so we've really been disciplined. And I think at this point, the saltwater disposal infrastructure is coming together nicely. We don't see any issues. But of course, we've only got first 2 wells online. So we're going to be watching that real closely. And certainly as we get towards the end of the year and into next year, you're going to see that ramp up significantly.

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

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 3 or 5 years, we'll get there. Some leases -- a big portion of the leasing capital that we have in our $1.6 billion budget goes to Southwest PA. And it's just simply filling in holes and blocking up, what I call blocking and tackling as we're drilling through that area. So it's hard to talk about absolute black-and-white numbers when things will be HBP because we'll be continually adding new leases as we get opportunities to bolt on. But we should substantially have all of that done in the next 3 to 5 years.

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

That's a great question, Marshall. And to be just flat honest with you, I don't have an 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. But just like we talked about earlier, every time we do more of that, it does cost more money. So we -- we're going to stay within our $1.6 billion capital budget and we're absolutely not going to spend more than that. So it's really a juggling act of where does it make sense to do it. It's certainly -- we're certainly not at a point where we can say it just -- blank it, makes sense to do it everywhere we go. But we'll be doing enough of it. Well, let me say it in another way, we'll be doing as much of it as we can. And I think in probably another quarter, I could give you a range or a percentage of the wells that we'll be doing those techniques on going forward.

And I think the key, again remembering the old techniques in the wet area where 3 years worth of data on almost 200 wells generate about a 75% rate of return, which is pretty exciting. And in the wet area, based on the first day, it's about 95. These are enhancements to that. I think what you'll see in time, into 2013, '14, '15, like Ray said, you're going to see, I think, continuing improvement.

Yes, let me add even more to that. We're also taking what we're learning there in the Marcellus and we're 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're 2 wells into it on a 100,000 net acres.

We are nearing the end of today's conference. We will go to Mike Scialla from Stifel, Nicolaus for our final question. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: I think you said you had 7 rigs running in the super-rich area, and how many total do you have in the Southwest PA now?

Today, there's 9 rigs total running in Southwest PA. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: So are those 2 that are in the wet area, I presume, is that kind of a good run rate to hold that area going forward, and you'll continue to concentrate on the super-rich?

It's going to go up and down, Mike. I mean, there's -- I don't have those averages because just like what we were talking about a little while ago, as we're -- as these new wells are coming online and we're starting to figure out what the potential is, you have to look at things like HBP, you have to look at infrastructure development and where does it make sense to change our plans in new rigs from the wet to the super-rich. So you're going to 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. So it's just going to ebb and flow. And so I don't think you could hold that flat. I think the only thing you could hold sort of flat would be in that 7 to 9 rig range throughout the year or so in Southwest PA. Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division: 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 could see a shift, more emphasis towards the Upper Devonian going forward?

Well, I think it's apples and oranges because the Marcellus is the entire Marcellus, which is all the dry acreage in Northeast PA and along with the dry acres 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 types, as you know. We got -- simply we just got to see some more results before we do go that far.

And it's so early in the Upper Devonian. The recovery factor for using there is even significantly less. So until we get more data -- what we'll do is continually update it with time.

We've come to the end of our Q&A session. I'd like to turn the call back over to Mr. Ventura for closing comments.

Okay. Before I give my closing comments, I'd like to note that we have several more questioners online that we weren't able to get to. So I would encourage you to give us a call, and we want to make sure we follow-up and answer your questions along with anybody else that might have some, so make sure to do that. But for the closing comments, I'd like to close with what I believer are the 4 main takeaways for Range. First, we have a very large acreage positions 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 in the plays that we're 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 5 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. I believe these 4 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.