Range Resources Corporation (RRC) Q2 2013 Earnings Report, Transcript and Summary

Welcome to the Range Resources Second Quarter 2013 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that are not historical facts are forward-looking statements. 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 would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, and welcome. Range reported outstanding results for the second quarter of 2013, with record production and continuing decrease in unit cost. Both earnings and cash flow per share results were greater than first call consensus. The order of our speakers on the call of the day are: Jeff Ventura, President and Chief Executive Officer; Ray Walker, Senior Vice President, Chief Operating Officer; and Roger Manny, Executive Vice President, Chief Financial Officer. Also, Mr. Pinkerton, our Executive Chairman is on the call today. [Operator Instructions] Range did file our 10-Q with the SEC yesterday. It should be available on the home page of our website or you can access it using the SEC's EDGAR system. In addition, we have posted on our website supplemental tables, which will guide you in the calculation of the 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. Now let me turn the call over to Jeff.

Thank you, Rodney. With our existing portfolio of properties, we believe that we can grow our overall production at a rate of 20% to 25% per year for many years. As the largest acreage position in our company, Range has approximately 1 million net acres in Pennsylvania as the engine that will drive our growth. We have both the assets necessary to grow our production and a proven team in place to carry out our plan. In addition, we believe that we've lined up the critical processing and takeaway capacity for the next several years. On the liquid side of our business in Pennsylvania, we have entered into 3 agreements to transport and sell ethane. The first project, Mariner West, commenced line fill on July 21. Since our sales point is FOB to MarkWest Houston plant, line fill to Range equals sales. The Mariner West project is significant in that the de-ethanizer at the MarkWest Houston plant in Washington County Pennsylvania is currently the only operating de-ethanizer in the Appalachian basin. This project is very important for Range in 2 regards: First, with the vast majority of our wet Marcellus gas being processed at the Houston plant, coupled with our dry Marcellus gas production elsewhere, 95% of our Marcellus production will meet pipeline specs, a key factor in ensuring that Range's gas will continue to flow. The remaining 5% of our Marcellus production flows to the MarkWest Majorsville plant in West Virginia, where de-ethanizers are expected to be in place and running in 6 to 9 months. If there are issues in the interim, Range has the ability to redirect the majority of the 5% of the gas that flows to Majorsville. The second thing that Mariner West project does is allows us to continue to grow and build our overall production volumes. Mariner West, combined with ATEX, which is projected to come online next year and Mariner East, which is expected to come online with the ethane portion of the project in 2015, will enable Range to sell 55,000 barrels of ethane per day. Assuming minimum ethane extraction, this level of ethane sales will enable us to produce 1.8 Bcf per day of wet natural gas into the processing plants. When this wet gas volume is processed, and the gas is shrunk and the natural gas liquids and condensate are added to it, we are projecting that these 3 projects will enable Range to produce about 2.2 Bcfe per day net from just the wet and super-rich portions of our acreage. Adding in the dry gas, we have the potential to exceed 3 Bcfe per day net. Bear with me for a couple of minutes and I'll quickly walk through the math. With these 3 projects, we have the capacity to produce 55,000 of ethane, barrels of ethane per day. Assuming minimum ethane recovery, this equates to 1.8 Bcf per day of wet gas into the processing plant. In addition to the 55,000 barrels of ethane, natural gas liquids and condensate could potentially total an additional 140,000 barrels per day. Total liquids production potentially could then be about 195,000 barrels per day. We're using a 6:1 conversion, 1.2 Bcfe per day net -- or Bcfe per day. After the liquids are removed from the 1.8 Bcf per day of gross inlet gas, the gas volume would shrink the 1.4 Bcf per day. Adding the 1.4 Bcf per day of natural gas to the 1.2 Bcfe per day of natural gas liquids and condensate equals 2.6 Bcfe per day gross, or about 2.2 Bcfe per day net. That's from the wet and super-rich portions of the Marcellus. If you add in the dry gas potential, we have the potential to exceed 3 Bcf per day from the Marcellus alone, with the 3 ethane projects we already have under contract. This is a key element which gives us the confidence a project 20% to 25% growth for many years. On a compounded basis, growing at 20% to 25% per year equates to doubling production roughly every 3 to 4 years. In addition to having the projects in place to extract, transport and sell the liquids, we have secured enough firm transportation and firm sales to handle our projected gas sales for several years. In 2014, we have firm capacity in term sales for over 80% of our production. Our team has been working on these projects for many years, and is putting the pieces in place so that we can continue to grow production profitably beyond our current arrangements. On the operations side, we just updated our results and provided our expectations for the future drilling in Southwest Pennsylvania of our super-rich wet and dry wells on an EUR per thousand foot of lateral basis. In addition, we've updated all of our projected reserves and economics for these areas based on our updated well designs. Well designs range from 4,200 feet to 5,000-foot laterals, with over 20 frac stages per well. The average projected recovery for these wells ranges from 10.9 to 12.3 Bcfe per well. As shown on Slide 23 of our investor presentation on our website, under current strip pricing, the rate of return for the dry, wet and super-rich projects are all about 100% pretax rate of return. Reinvestment risk in all 3 areas is low, and economics for all 3 areas are high. Therefore, our plans are to drill and develop all 3 areas. We also just released the results of our 500-foot tighter spacing project in the Marcellus. Based on 3 years of history, the project is very encouraging, and we're projecting that our 500-foot space wells will recover about 80% of 1,000-foot space well. That both increases our resource potential and provides us additional confidence that we can grow at 20% to 25% for many years with high returns, low cost and low reinvestment risk. I'll now turn the call over to Ray to discuss operations in more detail.

Thanks, Jeff. My remarks today will primarily focus on the Marcellus in Southwestern Pennsylvania. Our technical teams continue to make great strides applying newer technologies and approaches such as RCS, enhanced completion designs, longer laterals and better targeting. We've updated and provided guidance for our development plans for all 3 areas, dry, wet and super-rich, as well as adding some new data. There's been a lot of discussion lately concerning well performance on a normalized lateral length basis, so we've included actual performance data on a per thousand foot of lateral length basis for all 3 areas in Southwest PA, as we believe we have some of the best performance data in the basin. Wellhead economics returns in Southwest PA of strip processing in all 3 areas are now approximately 100%. The bottom line, all 3 areas are high-quality assets, and like our philosophy has always been, it's really about economic returns at Range. Our ability to achieve those high returns in dry gas drilling, wet gas drilling and drilling in the super-rich area allows us to confidently grow our production at 20% to 25% year-over-year for many years. Let's start with the super-rich area. We've now added Slide #14 in our presentation showing the actual production data of the 17 wells that we've discussed in the last couple of calls, as compared to the average production curve of our pre-2013 results. It's early, but the actual production data shows that these 17 wells are producing to sales 50% better than the pre-2013 curve, with over 4 months of production history. Again, this is not based on just a forecast, it's actual production data to sales and we are very encouraged by what we see so far. Also on the super-rich area, in early July, we brought online a new well that produced 3,670 BOE per day at 72% liquids, while choked back due to gathering system limitations. That rate included over 1,000 barrels per day of condensate. Just 2 weeks ago, it was the highest 24-hour maximum rate to date at any well in the Marcellus with more than 50% liquids. However, I'm happy to report that, that record did not last very long. Last week, we brought online another well approximately 10 miles away at 5,720 BOE per day with 63% liquids, which 24% of those liquids was condensate. This well is now the highest rate IP liquids well with more than 50% liquids, not only in the Marcellus, but in the entire basin, in the modern era that we're aware of. Again, these are only IPs, and it's still very early but we believe we are seeing some real upside potential as we implement these new well designs. I'm going to pause for just a second here and offer my congratulations to the Southern Marcellus Shale division team for the great results. And just like the team in Pittsburgh, I don't believe we've drilled our best well yet. On Slides 15 and 16, you can see our updated cost, EURs and economics for the super-rich area. You can also see our well performance on an EUR per thousand foot of lateral basis. We steadily increased lateral length and the number of stages while combining that with better targeting and completion science. We are now and into 2014 drilling 20% longer laterals and completing them with 50% more stages. All of this yielding better and better EURs, higher efficiencies, lower unit cost and the resulting economics that you see in our presentation. And we still believe there's substantial upside as we get more and more of these wells under our belt. In the wet area, we also continue to see improving well performance for all the same reasons. Going forward, we plan to drill, on average, 4,200-foot laterals and complete with 21 stages. We project these wells to have an EUR of 12.3 Bcf equivalent, which is a 41% increase from our last projection. We've also included in this analysis for this area an EUR per thousand foot of lateral basis comparison. Again, we've seen improvement year-over-year, and we believe we have some of the best wells in the basin that are on an EUR per thousand foot basis, are nearly 3 Bcf equivalent per 1,000 feet of lateral length. We brought online 15 wells in the wet area this year, with an average IP of 13.7 million cubic feet equivalent per day with 38% liquids. Those wells were mostly drilled in 2012, and averaged 2,627-foot laterals with 14 stages. It used to be that a single well IP of 13.7 million cubic feet equivalent per day was a real game changer. But let me point out that today's game changers that this is a 15 well average from only 2,627-foot laterals that we drilled back in 2012. Although these are really impressive completions to date, especially if you look at them on a normalized per 1,000 feet of lateral length basis, we are now drilling longer laterals with RCS completions and expect bigger EURs and no returns. In the dry area of Southwest PA, we brought online 16 wells so far this year, averaging 2,942-foot laterals with 15 stages. Again, those wells were either permitted or drilled back in 2012. But if you look at Slide #21 in our presentation, you can see that these wells, on a lateral length basis are almost 2.5 Bcf equivalent per thousand foot of lateral, and are already some of the best-performing wells in Southwest PA. Going forward, we're drilling wells in this area with an average lateral length of 5,000 feet, and completing them with 25 stages. We expect those wells to have an EUR of 12.2 Bcf, which is 2.44 Bcf per thousand foot of lateral, and we expect them to cost approximately $6 million. At today's strip pricing, these wells would yield a return of 97% and an NPV 10 of $12.7 million. It's important to point out with these newer designs, these wells now compete favorably with our super-rich and wet area economics. If you look at Slide #23 on the website, you'll see the real punchline. We've presented a side-by-side comparison of all 3 areas in Southwest PA. Economic returns in all 3 areas are approximately 100%, with EURs ranging from 10.9 up to 12.3 Bcf equivalent. Again, it's all about returns and cash flow at Range, and we believe this demonstrates the high-quality, low reinvestment risk and the diversity, along with the balance of our portfolio of projects. Okay, shifting to Oklahoma. For the Horizontal Mississippian play, we've become more aggressive with the frac designs, primarily going back to the larger frac jobs which are yielding really good results. There's 3 recent wells listed in the press release with these larger volume fracs with IPs ranging from 957 to 1,306 BOE per day, and oil production rates from 230 up to 625 barrels of oil per day. All 3 of these wells are in line with or above our expectations. Going forward, on average, we still expect to be right in line with our expectations of EURs ranging from 485 to 600 MBOE per well. I'll shift now to the other divisions across the company. In Nora, our last 4 horizontal Huron Shale wells have been the best-performing wells to date, so congratulations to Jerry and the team. They've implemented some new well designs and completions that appeared to be working really well. For Northeast PA and the other areas across the company, you can refer to our earnings release for updates on the activity in those areas, and we can certainly cover any of those areas during Q&A. Production for the third quarter will be set at 945 million to 950 million cubic feet equivalent per day, with approximately 22% of that production being liquids. We've had great success during the first half of 2013, and we're on track for the year to approach the high end of our previously announced range of 20% to 25% year-over-year production growth. In summary, our technical and operations teams all across the company are doing a great job, working safely, being a good stewards of the environment and good citizens of the communities where we live and work. We're really proud of our people and our high-performing culture at Range. We continue to work safely, protect the environment, meet our goals, make better wells and improve our cost structure quarter after quarter. All of this, combined with our high-quality, diverse and balanced portfolio, gives us confidence that we can deliver 20% to 25% production growth for many years into the future. Now over to Roger.

Thanks, Ray. 2013's second quarter extends the positive trends evident in the first quarter, namely, significantly stronger cash flow derived from higher revenue and lower unit cost. Oil, gas and NGL sales for the quarter were $416 million, up 34% from the second quarter of last year. Cash margin likewise improved, with second quarter cash margin coming in at $2.71 per Mcfe, a 15% increase over last year. With top line growth outpacing expense growth, cash flow for the second quarter was $227 million, 46% over last year's second quarter. Cash flow per share for the second quarter was $1.40, 44% higher than last year. EBITDAX for the second quarter was $269 million, 37% higher than last year. GAAP net income, which includes noncash hedging mark-to-market entries, asset sales gains and other non-recurring items, were $144 million for the second quarter. Earnings calculated using analyst methodology, which excludes these items, was $55 million, more than double last year's second quarter earnings of $18 million. Please remember that all non-GAAP figures I just mentioned are fully reconciled to GAAP on the Range website. You may have noticed that last year, we began sighting our unit cost guidance in our quarterly earnings release. With this practice established, beginning with this call, in order to allow more time for operations updates and Q&A, I will no longer be providing detailed quarterly cost performance commentary and guidance. I'll confine my remarks to quarterly cost items, where our actual quarterly results differed from guidance. Our first better-than-guidance cost item is third-party transportation gathering and compression at $0.80 per Mcfe, that's $0.02 below guidance due to the timing of expenditures, well hookups and a higher-than-projected production. We believe that $0.80 to $0.82 slot is a good estimate for the third quarter. Reduction in ad valorem taxes for the second quarter of $0.13 per Mcfe was $0.02 below guidance due to higher production from lower-cost areas. Our current estimate of third quarter production tax is between $0.14 and $0.15. Exploration expense, excluding noncash compensation, was $12 million for the quarter, quite a bit below guidance due to the timing of seismic expenditures. Our seismic budget for the year hasn't changed, so next quarter should see this expense increase to between $19 million and $21 million. Unproved property impairment for the second quarter at $19 million was $2 million over guidance, reflecting the write-off of some nonstrategic unproved acreage in Texas. Third quarter should see this expense back in the $15 million to $17 million range. G&A expense was $0.01 over guidance at $0.43 per Mcfe, due primarily to higher legal fees. We anticipate cash G&A unit cost for the third quarter to be between $0.40 and $0.42 per Mcfe. Lastly, interest expense on a unit cost basis is beginning to reflect the benefits of both higher production and the recent refinancing of several high-cost long-term bonds. Second quarter interest expense per Mcfe was well below our guidance at $0.54. Next quarter, we should see this expense fall another $0.02 to $0.03 in Mcfe. Over on the Range balance sheet, the major changes since last quarter are the closing of the Permian asset sale, which garnered an $83 million pretax gain and the early redemption of the $250 million 7 1/4 notes, which were pre-funded by the issuance of lower-cost 5% notes during the first quarter. And at the end of the second quarter, Range had approximately $1.4 billion in committed available liquidity under its credit facility, and approximately $1.6 billion in total available liquidity under our $2 billion credit facility borrowing base. Earlier in the second quarter, Range added to its 2013, 2014 and 2015 hedge position with additional natural gas, oil and NGL hedges. Please reference to Range website and press release tables for detailed hedge volumes and prices. In conclusion, the standout financial metric this quarter is the 46% increase in year-over-year quarterly cash flow. This increase illustrates the significance of steadily increasing production, combined with slightly higher prices and slightly lower cost. With production anticipated to increase 20% to 25% for many years to come, and our economies of scale still building, we look forward to many future quarters of cash flow growth. Jeff, back to you.

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

[Operator Instructions] Our first question comes from Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Jeff and Ray, question on your lateral lengths in terms of driving the increase in returns in EURs. Ray, do you think you're about where you think you're going to be from a lateral length in terms of 4,500 feet? Or as you move further throughout the year or next few quarters that you may end up continuing to push those out, lateral lengths even further like others in industry have? And would you expect similar impacts on EURs?

That's a good question, Ron. We currently have or are implementing the designs that we've just put in the presentation. So we're driving the wet area up to the 4,500-foot range, the dry area to 5,000-foot. And again, those, when we present them in the presentation, they're really an average of the whole program, so we're always drilling some that are longer than those, and some that are shorter. So our absolute goal is, yes, to drive these laterals longer and longer as they get in time. But right now, our best estimate of what we've got planned for next year are the numbers that we've got in the presentation, that we're presenting in the earnings release. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, good. And just on the 3 years worth of data you had on the down spacing, relative to expectations in terms of the 80% EUR of the 1,000-foot laterals, where does that -- where did that come out relative to your expectations and is that something that, as you move forward from a development standpoint, you'll plan on being closer to 50 or 60 acre spacing across your play? Or where do you think that will settle out?

I think the -- our expectations going into -- we're probably in that 75% to 80% range. I think we see that in a lot of different fields across the country. It's a little bit hard to estimate and that's one reason that we wanted to see some real production history before we came out with numbers. We're dealing with a shale that's clearly better than anything we've ever seen before, and I want to look at that. I believe that we think that there's potentially some upside, they could perform a little better than that as we implement some of the RCS and some of the better targeting that wasn't actually done in these laterals. So I do think there's more upside in that, and I'm not sure what the second part of your question was, but I do think we see that there'll be down space or a tighter spacing, is a better way to say it, potential across all through the Marcellus. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And is the 12 to 15 Ts just related to the Marcellus in your wet and super-rich areas? Does that include any -- or any resource potential for Upper Devonian or anything else?

No, the 12 to 15 TCF equivalent that we added is only Marcellus, and only in the wet and super-rich area.

Our next question comes from Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, when we think about the Southwest Marcellus and the rates of return that you guys have outlined, and you compare that to rates return on the Northeast or Nora, well those are held by production property, it would seem like are primarily held by production. You wouldn't want to be pushing the drill bit there, really at all. You'd want to be redirecting drill bit and all capital toward Southwest Marcellus. Does those -- put those up as potential divestiture assets over time?

I think, one, when you look at the wells in the northern Marcellus, or the stuff up in the Northeast, you're going to see the same-type thing. We didn't update it this time. You're going to see some wells where you're going to have 5,000; 6,000; 7,000-foot laterals, and we'll be -- obviously, we share that technology throughout the company. In fact, throughout the industry and knowing what and what others are doing as well, so beware. I mean, I think you're going to see some impressive things in the future coming from that team, and we have a really strong team up there as well. We always look at redirecting our capital into the highest return areas that we have. We're focused on growing production per share, reserves per share, cash flow per share and bottom line, like we said, we think can basically at that 20% to 25% double and double again. That's being said, we look at all of our portfolio, and we look at the opportunities in there. Clearly, we're focused on per share growth. We have sold $2.3 billion worth of assets or something like that in the last few years, so we try to do the best things and keep focused. Now that being said, we think, the -- just like Ray mentioned, the stuff in the Southern Appalachian Basin, although at today's prices it doesn't compete, but one, we not only is it all HBP, we own the minerals on a lot of it, so we actually have the royalty, which is a real advantage. And the little bit of capital we've spent there, they're doing the same thing, they're drilling longer laterals with more stages and significantly improving the returns there, which we haven't shared with you and updated, but there's a lot of upside and potential. But that being said, we will continually look at doing what we think is most optimum things for our shareholders. David W. Kistler - Simmons & Company International, Research Division: Okay, I appreciate that. And then, maybe as a follow-up, dive in a little deeper in to the Southwest Marcellus, as you build out the ethane delivery capabilities and go from, call it 1,500 to 15,000 to 65,000 barrels of ethane extraction, can you relate that to what that means in terms of the amount of gas you can be producing, without violating pipeline limitations? In other words, the gas -- the true dry gas production growth that a company is that, or that's facilitated by that?

I'll try to walk through some of those numbers that I did earlier. I know that was a lot of numbers, and I went through them pretty quick. But with -- just with the 3 deals we have in hand, combined, those 3 deals are 55,000 barrels of ethane per day. So and that's just, obviously related to the wet and the super-rich, so that enables us to put 1.8 Bcf of wet natural gas into the processing plants with those 3 deals. And again, with the 55,000 barrels of ethane and the 1.8 Bs of gas, you get in an additional 140,000 barrels per day of natural gas liquids and condensates. So it's 1.8 Bs of gas plus -- and when you add the 55,000 of ethane, and the 140,000 of natural gas liquids and condensates, 195,000 barrels of liquids, plus 1.8 Bcf per day into the plant. And in addition, so that's what -- just those 3 deals. Obviously, our team is looking ahead to grow and do everything else, and then on top of that, then you've got to add the dry gas areas, which you don't need the processing for. Indeed, we have great dry gas position in the Southwest PA and again, we went through there. We think in the Southwest, and when you look at those things on a per lateral foot basis, they're excellent and drilling 5,000-foot lateral with 25 stages, we think they're going to be over 12 Bcf wells. And plus, we've got some great dry gas acreage in the Northeast as well. So and that's really what I was trying to lay out. Our team's done a very good job. We have a long-range plan looking at how we're going to develop the asset, how we're going to grow at that 20% to 25% or wherever ends up being optimum and have laid in place to take away for the ethane, take away for these other natural gas liquids, and as well as layering in the dry gas pieces. And then on top of that, you have to fold in the rest of the company and what we do with that as well. That's why we have the confidence to say we can consistently drill at 20% to 25% per year with -- at low cost, with high returns. Again, going back to Page 23 in the rates of return that Ray mentioned. So that hopefully that answered your question. So it's 1.8 Bs just in that area, plus all those 195,000 barrels of liquids plus your dry gas. David W. Kistler - Simmons & Company International, Research Division: That does, if I could just do one more follow-up. When you start outlining that kind of gas production and we think of peers who are out there, both in dry gas, wet gas window, people who are in the dry gas window of the Utica, ultimately, what does that do for you guys, in terms of thinking about the macro gas picture? Is gas ultimately, then going to be, surpassing the demand of the Eastern markets and flowing back to Gulf Coast markets and what might that mean to pricing?

Well, I think, you always look at the pricing, where the markets are, and we've got 80% of our 2014 needed transport and marketing arrangements already in place. That other 20% really allows us to hit the spot and other attractive markets that are developing because of the displacement that the markets -- that the Marcellus is doing. There will be some pricing pressures in certain areas of the Marcellus where more gas is coming online than producers have a market for. Luckily, in the Southwest area, we're fortunate to have 6 of the largest pipelines in Appalachia running through the core of our Southwest area. We estimate that, that would equate to 15 to 20 Bcf a day of transportation capacity and opportunity to reach markets that are a forward haul or backhaul, as you alluded to, to hit those markets as to where you need to be. Fast markets, generally in the U.S., the premium markets are going to turn over about every 3 to 4 years, so therefore, you need the flexibility to hit those markets and keep those market arrangements fresh. So that's our portfolio and that's what we're focused on. Therefore, we think the capacity that's already in place, then as they have additional expansions come on in the basin, that will actually relieve the pressure on those existing capacities, which should give us more opportunity.

Our next question comes from Leo Mariani with RBC.

Just kind of sticking with the Marcellus here. Obviously, you guys dramatically increased your type curves in Southwest PA. One thing, just noticing on some of those numbers is that it looks like really the NGL and the gas components were up significantly in the EURs, while the condensate component really wasn't as much. Could maybe you guys address that?

What we've done is, like we've done continuously over the last 6 or 7 years is, as we get more and more data, we're just trying to refine that and make better and better estimates. I mean, that helps us forecast what we need as far as capacity and condensate sales and storage and facilities and all the things that go with that, so that's been a gradual process. So what we're putting forward is, what we believe we're going to expect to see going forward. And I think the condensate issue, we believe there's some upside there, there's no question about that. We clearly got some IPs that are huge, that are really fun to talk about. But I think we're going to be reluctant to forecast those wells until we see a lot more of them. Those -- we don't want to take something that's a highlight real type item, and then build all our forecast off of that. So we're still looking at a lot of normal distribution of results and we still try to use that going forward. So everything we've put in here is our best estimate going forward, and we did put some new type curves in the back of the book, Page 36, 37 or -- and 38, to update all of those and their byproducts. So you'll see all of the actual things. And that's all based on wells, actual wells, that we have planned for '14. I mean, we've got well names, we got most of the permits in place, everything's already set, so I think that's a very good approximation of what we've got planned to go forward.

All right. So you guys aren't seeing, maybe declining condensate yield on the wells in the wet and the super-rich, at this point?

No. I think it's more a factor of just where you drill. I mean, as we go from the East side to the West side, your BTU changes, your maturities, so you've got more condensate on the West side, more heavier portions of the NGL barrel. You also have more ethane on that side. You just flat got more liquids. We've got some wells that are 80% plus liquids, all the way down into the low teens on the eastern edge of the wet areas. So I think it's just more timing and when those wells hit on the schedule and all of that. And again, what we're doing is taking all of that and making a forecast at an average type curve, and putting that in the book, so it's probably just more of an impact of that than anything else.

Okay, and I guess on your dry wells in Southwest Pennsylvania, if you guys have these bar charts in terms of [indiscernible] in '11 and '12, and then sort of forecast for 13 and '14, that one kind of stand out a little bit to me, because it looks like your EURs per 1,000 lateral foot on the dry in Southwest PA were actually going down a little bit where the wet and the super-rich were going up pretty substantially. Just wanted to get some color on why you think that is there?

Sure. The wells that are coming online in '13 are actually wells that we planned, permitted and probably mostly drilled in 2012. A lot of those weren't -- were not using the best targeting methods that we know today. They weren't using RCS completions and different things like that. So you're going to see that impact things going forward. But what we've also done -- what we've typically done is, as we drill these much longer laterals, we're not assigning a 1-for-1 add, as you add stages going forward. We're taking a real conservative approach and putting the risk factor on those additional stages that might be further and further out in that longer lateral. In other words, 1 plus 1 is not always 2 in our mind when you're adding that. So that's -- it's just simply our best conservative estimate at this point of what those wells will be. Will they do better? I actually believe they will, but again, there's still a lot of upside in that area, and we're seeing some really impressive results there. And looking at -- it's not only us looking at offset operators in the area, there's some really nice wells that are being made out there. So we, again, believe, there's -- we're going to see a lot of upside in the EUR per thousand foot even when you look at it that way.

All right, and I guess, am I correct in assuming that you've got a lot fewer wells and fewer production history in dry in Southwest Pennsylvania versus the wet areas, is that right?

Oh, absolutely. Yes, that, a lot of that acreage is already HBP-ed for us. It was legacy assets that we had, and -- but we don't have the same number of wells there yet, that we have in the wet area.

All right, so I guess that would explain the conservatism here overall for you guys then?

Absolutely. Yes.

I guess just jumping over to the Mississippian real quick, I think you guys have previously talked about on prior calls, now roughly doubling the rig count in 2014, getting roughly double the activity. Obviously, I know you guys have added efficiencies, you don't have to add as many rigs, but given a bit of a slow start to the year in the program, I know you guys explain that in your press release. And also given the fact that the returns on the Marcellus look like they've improved quite a bit, we potentially expect lower levels of activity in the Miss, and maybe shifting more activity to the Marcellus next year? How we -- should we think about that?

I think the best way to answer that is, that we've always said the Horizontal Mississippian play is really an emerging play. We've got 160,000 net acres there. It looks real impressive to us. We have experimented with different style fracs and designs and so forth. We feel like it's on track, things are looking pretty good. But at this point, like we said, even though we used to say in the past it was going to be 5, 10, 15 rigs forward, that was always with the caveat that we had to see the results going forward. And that's why it's only a small portion of our budget and so forth. But I think we'll reserve the right to make that decision until we lock in the budget towards the end of the year with the board. But I do think there's still a lot of upside there, but we're just going to have to wait and see what the results look like at the -- towards the end of the year.

Our next question comes from Doug Leggate with Bank of America Merrill Lynch.

I guess, I'm afraid I'm going to go back to the Marcellus as well. The pace of completions in the second half of the year clearly slows down quite dramatically. Is that a function of the higher cost of the longer lateral wells? And I just wonder if you could help us with a little bit of color as to how those sort of wells are much higher return, or at least a much higher return, with a higher CapEx. What does that mean in terms of activity levels, as it relates to rig count going into 2014?

Doug, that's a great question. I think the -- it's more related to the fact that we've got a big capital budget. We're not going to raise it, we're going to stick to it. And what we saw early in the year is what we've seen for the last several years, is the Southern Marcellus shale division, just like a lot of divisions across the company, is making really great improvements in efficiency. I mean, the rigs are down to 4 or 5 days in some cases now. The frac crews are doing 9 stages in 24 hours, where a year ago, they are doing 3, 4 and 5 stages in 24 hours. So what happens is, you kind of by default end up frontloading the capital during the front portion of the year because we just get a lot more wells online. So we'll see a gradual slow down. We are also with the longer laterals. It's basically the drilling rate. The drilling rate times not a lot longer, but the completion time does add to it, when you go from 14 stages to 20-plus stages, it will take longer. And so I think when you combine those 2 things, you're going to see what we typically have always seen up there in the Marcellus, that the year tends to be frontloaded and then the rate of completions or the rate of wells coming online towards the end of the year will slow down.

Okay. That was very clear. So just to be -- I guess, just to be clear on that, so currently, your backlog is in the low 40s, as I recollect?

I'm sorry, I didn't understand the question.

The backlog of uncompleted wells is sitting in the low 40s, where would you expect that to get to by the end of the year?

I think the total backlog is about 70, and I think it will come down slightly by the end of the year.

Okay. I guess, my follow-up is really going back to the question about the lateral end. I mean, you've talked about obviously, you've stepped these up pretty ratably over the last several years. But are you testing longer laterals beyond what you've disclosed in your latest guidance? In other words, where does the 4,000-foot lateral go to next, in terms of what you think might be optimal over the [indiscernible]?

Yes, absolutely. And again, remember, these type curves and economics that we're quoting for you are the average of the program going forward through 2014 and into '15, actually. So, yes, we will drill quite a few longer laterals and quite a few shorter. I think our longest lateral today is about 6,000-foot. I suspect we'll probably go to 7,000 in some cases. The wells, the highlight well that I talked about being over 5,000 to 5,720 barrel a day well, that was a 5,000-foot lateral. So we're already doing it, and yes, and we will continue to basically experiment with longer and longer laterals and more and more stages, trying to find that optimum project return, which is what we're focused on, so.

Yes, is there any limitation in terms of having the older sections bolted together that might limit you going to a more aggressive well design as we go forward?

No. I think, the team's doing a great job of planning and looking at those opportunities and just consistently really, ever since we've been in the play, year after year, the wells get better. And given where we are, and given the fact that probably longer laterals with more stages, better targeting, more RCFs, will probably continue to drive up performance.

Our next question comes from Dan McSpirit from BMO Capital Markets.

In years, what do you model as the life for wells drilled in the Marcellus? And in what year is terminal decline achieved? And as a follow-up to that, does any of that change much with an increase in lateral length or change in completion design?

Well, we have with us Alan Farquharson, Senior Vice President of Reservoir Engineering, so he heads up all that for the entire company. I'll just turn it over to Alan then, of course.

Thanks, Dan. First of all, the life that we model is about 45 years, out for the Marcellus is what you're seeing in there right now. I cannot specifically give you when we get to the terminal decline rate right off the top of my head, but I can tell you that we do use a multiple decline rate. We're using more than 2 in the projections that we have, so you're not looking at a single B factor going throughout the entire life of the well. I'd have to get back to you on the exact time of when we hit a terminal decline rate, but it's fairly far out in the future.

You can coordinate with our IR team, and they can set a call up with Alan to get into some more of the specifics.

Okay, great, and just maybe a follow-up to that, is there any impact on the decline rates on wells drilled under the tighter spacing scenario, if at all?

Well, I think your question is, is the shape of the curve going to look a lot different on tighter wells than what it is on the wider spaced wells?

Right.

Is that kind of the general question? Now as you can kind of see in the book on...

Page 25.

On Page 25, they actually do follow a relatively similar decline rate and obviously, a lot of those wells, with 3 years of history, we -- that was one of the reasons, as Ray mentioned earlier, we want to make sure we had enough information on these wells before we came out and talked about them. But overall, to date, they found very, very similar production profiles in terms of decline rates.

Okay. Great. And then lastly, just turning to the balance sheet, quickly. Can you repeat for me the leverage goals for year end, and maybe periods beyond?

Yes, sure, Dan. I mean, we -- Range is an operating strategy driven company, not a financial strategy driven company, so we don't have hard leverage goals out there that we're going to manage to. We're going to manage the operations first, and then we're just going to keep that leverage and, for a lack of better term, our comfort zone. And as we've kind of talked about before, that comfort zone extends into the low 3 times debt-to-EBITDAX range, and then obviously as low as it needs to go to address the times that we're operating in. So right at about 2.8x, trailing 4 quarter debt to EBITDAX at the end of the second quarter, it's well down from fourth quarter of last year. And as we've said, based on current prices in our current hedge book, that ratio will grind down over time, not to any specific objective, but clearly at 2.8, we're very comfortable with that level of leverage, and are just fine anywhere in that zone.

When you look at that long-term plan, about 20% to 25% growth for many years and basically doubling every 3 to 4 years, keeping our capital outspend to that $250 million to $350 million over cash flow in the early years, as we continue to grow, we strip pricing, we significantly de-lever over time, so.

Our next question comes from Hsulin Peng with Robert W. Baird. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: So my first question is, given that you're drilling longer lateral wells, can you discuss how this will affect your HBP schedule for acreage in Marcellus?

Yes, I think we're in great shape there. We break it out by area, and like we've said many times, we've got a plan to basically hold all that acreage we want to hold. It'll happen with time. And I think an important thing to consider beyond that is, in addition to drilling to hold it which we'll ultimately do, all the leases that we'll be drilling also have extensions, on that number of tickers, so we have more than enough time to hold acreage, but we have a clear plan for that, and that will happen, and will. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then, so a more high-level question. Given the updated resource potential and nearly 2 million acres with a stack pay in the Northeast, can you give us your current thoughts on how you are thinking about, in terms of potentially accelerating or optimizing the value of these assets, especially in the back end of the value? If you're happy with the status quo, with the organic growth, how -- I guess, what could be some trigger points where you or and the board could reevaluate your strategy?

Yes, we do that, really in realtime, I won't say constantly, but frequently. It's something we're always looking at, is how do we maximize the value of our company. So again, I've said this before, at year end last year, where you're at net, at around 0.8 Bs per day, 20%, 25% growth in 3 years, we think we'll be about 1.6 Bcfe per day net. And go out another 3 years, that's 3.2 over 3 Bs. So we think, in that, from the end of the last year, in that roughly 6-year timeframe, we'll be over 3 Bs per day net, which is -- and I tried to lay that out pretty clearly in my notes upfront, near my call notes upfront, to say that we've got the liquids agreements, and a lot of the gas processing and everything in place to get there, which is phenomenal growth. The key is, it doesn't stop at 3 Bs per day, with the inventory we have, 3 can become 4, 5 or 6, which is, and then again, look at all the other E&P companies in the U.S. on a net basis, that's phenomenal growth for a company our size, with our market cap. Importantly, from very low-risk areas that, basically all that acreage in the Southwest and in the North East is de-risked. So it has very low reinvestment risk, there's a lot of drilling around it, the quality of the wells are excellent, yet they're getting better. Costs are coming down so we'll look at that all the time. We think we have a great plan that laid out, so we're not just looking at what do we want to do in 1 year or 2, it's in what do we want to do in your 1, 3, 5, 10 and beyond. However, we continually look at optimizing it. Like I said, we've sold $2.3 billion or so worth of assets in the last few years, so we're always looking at building and high grading as well, or where there more optimum ways to do it. But what we really think, if we -- if nothing else, if we just consistently execute on the plan we laid out, we think we will really drive up production per share, reserves per share and cash flow per share consistently with time in one of the highest rate of return plays out there. That being said, we'll always look and see if there's better ways to do our business. Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division: Okay. And then last question is more macro. So we have seen a bit of volatility with the Appalachian basis differential recently. And so I'm just wondering if you can give us more details on how you're -- where your pricing points are in -- within Appalachia, how you sell the contract for your gas sales, and how do you navigate through these volatile differential environment?

We've got a great marketing team that's been doing this. So the contracts that we have today were put in place 2 to 3 years ago. That was a time to put them in place for these types of times, so that you've got contracts with pricing that goes through the soft periods as other producers bring on gas. Range does not bring any gas to market that doesn't already have a buyer on the other end, so we're not pushing any of that basis differential. Then we've moved our contacts to stay out as much as possible out of any Appalachian indexed type of price to minimize that. And then, of course, we've got our hedge position from that area. But basically, with the flexibility that we have, with the dynamic market that you have, with marketing arrangements and working with one of the largest producers in Appalachia, we have access to a lot of markets that give us this opportunity to lock in prices on a long-term basis. And that's going to be able to get us through these periods of time until other facilities, other producers get built, that allows us to continue to maximize our value.

Our next question comes from Neal Dingmann with SunTrust.

Say, just a question on the Slide 10, where you guys break out by the wet and dry acreage and show different stack pays. I was wondering, kind of question about the Utica. Obviously, it looks like you do have a lot of potential for the Utica and, again, I'm just wondering as far as going after that or drilling other than that prior well that you had. Is that more dependent on waiting to see other results? Or given how successful you've been in the Marcellus and starting to be in Upper Devonian, why go to that now at this time? I'm just wondering what your thought processes is on that.

Yes, you make a great point. On Slide 10, we're pointing out for those of you that haven't looked at it, we think, not only do we have 1 million net acres, really when you look at the stack pay potential, we lay it out on Slide 10, it's prospective for a number of horizons. Neal specifically asked about the Utica. And we have 180,000 net acres, wet acreage in the Northwest and 400,000 of dry in Southwest. The good news is all the stuff in the Northwest is HBP. When you look at the stuff in the Southwest, any well, to any horizon holds all horizons for us. So we have such prolific Marcellus wells, and it's so low risk at this point in time. Like I said, essentially all that acreage is de-risked. We'll just consistently drive up production and cash flow and reserves with the Southwest and hold those opportunities. The good news is, in both areas, there's a lot of drilling around us, some in of the Northwest and also, even in the dry, there's some wells that are coming right up against our acreage position. Of course, we're going to route those wells on. And then, we have the ability to stay focused on investing our dollars on low-risk things to generate returns, yet to the extent those other operators have success, we'll be able to capture that. To the extent they don't, we'll have saved some risk investment, but we think there's great potential. And particularly, it's interesting to look at the stuff in the Southwest, when you map high-quality rock, we have great Utica potential down there. It's high porosity, it's going to be high pressure, it's thick. And then, of course, it's stacked, so then you have all the advantages of infrastructure, roads, plants, pipelines, team and all that type of thing. So very excited about the potential but in the interim, in the short run, we're going to stay focused on the Marcellus and see how the rest of that plays out. And then we'll come back with, to the extent it's successful, what's the most optimum way to capture the value.

That makes sense. Two more if I could, Jeff. Just looking at your maps, they're at very good detail. You certainly have the dominant position in Marcellus and/or one of the dominant positions. But what's evident is there certainly somewhere you control, and there's a little bit, kind of little holes here and there. Is that going to enable you to add, maybe not but some might call material, but still add a fair amount of acreage for relatively low prices, because you can kind of walk some people out, if you will?

Well, I think there will be opportunities with time when you get a big blocky position like that, and there are small holes with time then. Your point's well taken, that we would be the logical person to pick the acreage up. We'll have infrastructure to take away the team, the pad and it'll be most efficient for us to develop it, so, yes, we'll clearly look at those opportunities and, therefore, you could see us capture some of those, with time.

Okay. And then just last, maybe a quick one for Ray. I know others we hear more about, maybe in the Eagle Ford and other areas, about people adding more sand per stage, and trying to obviously squeeze more out of that. Just wondering, Ray, maybe your thoughts as far as you guys obviously having fantastic results, besides maybe this multi-cluster. I mean, is there things to add more sand per stage, or what's your thoughts about that?

Well, I think that all across the industry, people are focused on more stages in the lateral, more in better conductivity in the near wellbore region, and all of that. And, yes, we've been working on that since we started in 2006. We're continually looking at proppants, different mixes of proppants, different amounts of proppants, different concentrations and all of that. And I think that's just going to evolve over time. And one of the other things, the Marcellus is such -- it's in the largest hydrocarbon basin in North America, and I think sometimes we fall in the trap of thinking the Marcellus is the Marcellus everywhere, and it's not. It's not even the same from one side of the super-rich to the other side of the super-rich. And so, I think you're going to see all the operators talking about more conductivity, more frac jobs, more stages and working through that. The good news is, we're all exchanging data now. So we're doing lots of technical reviews on a quarterly basis and different things like that, that are helping everybody move up that learning curve faster. So yes, we are doing it, and I do expect there's going to be some upside in the well performance due to that, also.

We are nearing the end of today's conference. We will go to Louis Baltimore of Macquarie for our final question.

So your newly increased EUR estimates for the super-rich wells appear to be based off actual production from 17 wells drilled during the first quarter, that have average lateral lengths of 3,500 feet in 18 frac stages. Yet the new well design calls for 4,500 foot lateral lengths with 22 stages, and uses that same EUR estimate. So given the additional 1,000 feet of lateral, and 4 more stages, it would seem like these new EUR estimates are already too low?

Well, I hope so. One of the things that we don't want to fall in the trap of just like, we have always been very data based in our projections. And those 17 wells, I totally agree with you, look like they could be in the range of what we're projecting for the wells going forward, with longer laterals. But again, we're not -- we want to see more data on those 17 wells, so we've only got 4 months of history so far, and we want to make sure that, that's consistent. We've been applying a lot more RCS, we've been changing our targets and optimizing that a lot more, and we're still going up the learning curve in the super-rich area. We don't have the history quite there yet, that we have in the wet area, so we are being conservative. And we don't want to take some really, some -- a group of wells that are really performing well in 1 specific area, and then base everything off of that, until we get more wells under our belts. So you're pointing out a great point, and it gives us confidence and that plus some of the EURs, like the wells I talked about in my remarks, and in the press release that are longer laterals and clearly going to be above those curves, all of that gives us a lot of confidence that there's a lot of upside, but we're not really wanting to model our forward projections on that yet.

Thank you. This concludes today's question-and-answer session. I'd like to talk to in the call back to Mr. Ventura for closing remarks.

Given Range's large, high-quality low-risk acreage position and drilling inventory, we continue to believe that in addition to growing production 20% to 25% this year, we have 20% to 25% line of sight growth for many years. With the high returns in our projects assuming current strip pricing, our cash flow is expected to outpace our production growth. We're also projecting that with current strip pricing, we'll be reducing the leverage of our company with time, as we drive up production and cash flow. Led by our approximately 1 million net acre position in Pennsylvania, we project that we will consistently drive up production and reserves on a per share basis, net adjusted for years to come. Plus we continue to be one of the lowest cost producers in the peer group and are still improving. We believe that this plan will translate into substantial shareholder value in the months and years ahead. Thank you for participating on the call.

Thank you for your participation in today's conference. You may disconnect at this time.