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…

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…

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…

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…

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.