Range Resources Corporation (RRC) Q2 2014 Earnings Report, Transcript and Summary

Welcome to the Range Resources' Second Quarter 2014 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 turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, LaTonya. Good morning, and welcome. Range reported results for the second quarter with record production and a continuing decrease in unit costs over the prior year. The order of our speakers on the call today are: Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President and Chief Operating Officer; and Roger Manny, Executive Vice President and Chief Financial Officer. In addition, Chad Stephens, our Senior Vice President in charge of marketing, will be available to answer questions after our prepared remarks. Range did file our 10-Q with the SEC last night and should be available on the homepage 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 reported earnings to our adjusted non-GAAP earnings that are discussed on the call today. Now let me turn it over to Jeff.

Thank you, Rodney. The Range story is simple, to create value on a per-share basis by driving up production and reserves at low-cost. We have a long track record of doing just that, focusing on per-share value creation. Looking ahead, we believe that we have the wells identified, the compression and plants planned for, and the takeaway capacity lined up to profitably grow our production to greater than 3 Bcfe per day. The plan is further de-risked given that assuming current strip pricing and differentials, we project that we can be cash flow positive in 2016 and that our planned growth beyond that can be within cash flow. Importantly, we project that we will continue to grow 20% to 25% in 2016 and beyond, and gas demand is projected to grow significantly from LNG exports, petrochemical, power generation, manufacturing and transportation growth. As we continue to improve our drilling and completion technology, including drilling longer laterals with more frac stages, our capital efficiency continues to improve. For the second half of 2014, we plan to drill Marcellus wells that are projected to have an average lateral length of 5,413 feet, some with laterals over 10,000 feet. On our first quarter conference call in April, it was great to announce that Range has just drilled what we believe is the highest rate Marcellus well ever drilled by any company in the southwest portion of the play. That will had an initial 24 hour rate of 38.1 million equivalent per day. This well had its 7,065-foot lateral completed with 36 stages and it's located in Washington County, Pennsylvania. This quarter, I'm excited to announce that we drilled and completed our best well ever on our northeast acreage position. This well had an initial rate of 28 million per day from a 6,553-foot lateral with 33 stages. It could have IP-ed for a much higher rate, but was constrained by our surface facilities. This well set a new 30-day production record for Range and average 25 million per day for this period. This well has been online now for 40 days and is still producing 22 million per day. The cost of drilling to complete this well was $5.2 million. They have multiple potential offsets to the well. We expect to see capital and operating efficiencies build in the future from other areas. In the next 3 years, our land budget in the Marcellus is projected to decline significantly. This year, land is about 14% of our total capital budget. In 2017, it's projected to be about 5% of our capital budget. Unit costs are expected to continue to decline as we build scale and spread our already low cost across a larger production base. Importantly, Range has the largest net acreage position in Pennsylvania, with what we think has the best stacked pay potential. We believe we can grow annual production rates at 20% to 25% for many years, with net production of approximately 1.1 Bcfe per day net. Going on a compounded basis, our net production should double every 3 to 4 years. We have the potential to grow 1.1 Bcf per day to greater than 3 Bcf per day. For investors who stated that we have resource life of 100 years today, we believe we can drive that down to about 30 years in the next few years, and we should generate a lot of value pulling that forward. As we have seen repeatedly, marketing is the key to success in the Marcellus. Importantly, our marketing team is well coordinated with our operations teams. We currently move our gas on 11 different interstate pipelines into 21 different indices. Range has the most diverse portfolio of interstate pipeline firm transportation arrangements with some of the lowest cost per MCF direct-to-markets with strong demand. We have recently announced new long-term transportation of sales agreements that are aligned with our growth. We continue to expand selling natural gas in the eastern, southern and midwestern areas of the U.S., as well as selling natural gas to international LNG customers. Our ethane will be sold in the U.S., Canada and Europe, and our propane will be sold in the northeastern and midwestern U.S. and international markets. I believe that Range's ethane portfolio is the best in the business. Next year, when all 3 projects are online, selling ethane for us is projected to be greater than a 25% uplift in ethane revenue versus selling the ethane as gas and receiving the Btu credit. Turning to new developments in the first half of this year. We're currently drilling our first Utica well in Washington County. Our hope is that this well will unlock the Utica potential in our acreage in Southwest Pennsylvania. We currently have 400,000 perspective net acres that appear to be located in the core of the Utica with the highest resource in place. As we previously reported, we closed our asset exchange with ETP in mid-June. We believe that we created a lot of value by combining together both halves of the Nora field. In the southern part of the Appalachian Basin, combining our Nora assets with our other assets in this division, we now have 111 million cubic feet per day of net production, 475,000 net acres, 1,500 miles of pipelines and 85,000 horsepower of compression. We own the royalty under the vast majority of this production in acreage. We believe there's great upside to these properties and that we have the potential to grow this division to more than 500 million per day. This division alone has a deeper inventory and longer track record than many start-up companies. We continue to make progress in the Horizontal Mississippian Chat play. If you look at the horizontal wells with our original completion designs and also our current completion designs, we're projecting EURs with greater than 485,000 Boe. We plan to continue to drill and delineate our Mississippian Chat acreage through the end of the year. The wells turned to sales in this quarter have the highest average IP rates than any other quarter. As I mentioned on previous calls, in order to create significant value over time, the ability to execute well is vital for any company in our industry. This quarter was another great example of Range overcoming difficult circumstances despite MarkWest having a 200 million per day processing plant go down for 5 weeks in the quarter, due to severe weather. Thanks to the extraordinary effort for many members of our team and the MarkWest team, we were still able to exceed production guidance for the quarter. Congratulations to Ray, John Mike and our many dedicated employees who made this happen. I'll now turn the call over to Ray to discuss operations.

Thanks, Jeff. I'll start with our Southern Marcellus Shale division. When you consider our 530,000 net acre position in Southwest Pennsylvania, which includes Marcellus, Utica and Upper Devonian, we effectively have about 1.4 million acres to develop. Even without the stacked pay, this is the largest net acreage position in the southwest portion of the basin, and it's a high-quality position where the majority is core, meaning it's in the highest hydrocarbon in place of the basin for the Marcellus, Utica and Upper Devonian. It's also the highest quality acreage from a well performance standpoint in that we have the highest EUR per foot of lateral in the Marcellus in the southwest portion of the basin. To expand on that point, I'll discuss a couple of recent examples. Right before the last call, the team completed a 5-well pad in our super-rich Marcellus area. One of those wells had a 24 hour IP of 38.1 million cubic feet equivalent per day or 6,357 Boe per day with 65% liquids, and is the largest reported IP in the southwest portion of the basin. The 5 wells on that pad under constrained conditions had an average 30-day rate to sales of 2,113 Boe per day per well, and averaged 6,634-foot laterals with 34 stages. It's early, but the wells are estimated to have an average EUR per well of 16.3 Bcf equivalent, which translates to about 2.5 Bcf equivalent per thousand-foot of lateral. These wells are the best liquids-rich wells in the basin and are great examples of longer laterals combined with our latest targeting and completion designs. Using all our current commercial terms, deducts and strip pricing, the return on these wells is approximately 140% with a PV-10 of almost $25 million for each well. Another example in southwest PA in our dry area, we recently completed a 3-well pad that averaged 48 million a day combined for the first 30 days, again, under surface facility constraints. The wells had average lateral lengths of 4,768 feet with 25 stages, and our early estimate of the average EUR per well is 17 Bcf or 3.6 Bcf per thousand-foot of lateral. Again, using all the current terms, deducts and strip pricing, the return on these wells is over 185% with a PV-10 of over $19 million each. These wells are clearly some of, if not, the best wells in the dry area of the southwest portion of the play, even though they're about half the lateral length than some of our offset competitors. We're also seeing capital and operational efficiencies in southwest Pennsylvania continue to improve. Before I get into some specific examples, I want to point out that these efficiencies are driving improvements at the bottom line and we believe that the improvements will continue. This is a real testament to the incredible team that we have in place. On the completion side, we've safely executed 18% more stages in the second quarter of this year as compared to last year, and additionally, we see an 8% increase in the number of stages per day. This improvement in efficiency in just a year's time is really a nice accomplishment when you consider we utilized the same number of frac produce and are effectively pumping the same size, if not larger, jobs. Over the last 5 years, we've seen a 70% improvement in completion efficiency and again, we believe those efficiencies will continue to improve. On the drilling side in southwest Pennsylvania, we have achieved a 9% reduction in cost per foot this year as compared to 2013. And we fully expect that the drilling cost reduction will easily exceed 10% for 2014. Over the past 2 years, we're drilling 46% longer laterals at a 32% reduced cost per lateral foot. Essentially, we're drilling more complex wells at a significantly lower cost per lateral foot, and again, we believe this trend will continue. In the second half of 2014, we expect to drill laterals that are approximately 12% longer than those drilled in the first half of the year and longer than were in our original 2014 plan. Just to point out a few examples of those remaining in our 2014 drilling schedule, we have 9 wells planned between 6,000 and 7,000-foot of lateral length, 4 between 7,000 and 8,000, 4 more between 8,000 and 9,000, and 4 laterals that are currently targeted to average over 11,450 feet. We've also increased our lateral lengths for 2015, and you can find those on our updated presentation. As Jeff pointed out in his remarks, we're currently drilling the Utica well in Washington County, Pennsylvania and the plan is to drill a 6,500-foot lateral and complete it with a 32 stage completion. We spud the well back in April with the shallow rig to do the top well work, and we recently moved in the big rig and everything is on track for a production test in the fourth quarter. And recent offset activity continues to be very encouraging, as we believe we could have some of the highest gas in place for the dry Utica beneath our core Marcellus and Upper Devonian acreage. In summary, we have an acreage position in southwest Pennsylvania alone that, by itself, is larger than most of our peers and is in what we believe to be the highest hydrocarbon resource in place in the basin. If you look at our southwest Pennsylvania position as a standalone company, the compounded annual growth rate for the past 5 years is over 73%. We're continuing to drill longer and longer laterals while still maintaining or improving our recoveries, and our capital efficiency metrics are continuing to improve with what we see is a lot of upside yet to recognize. Shifting to northeast Pennsylvania. We have approximately 110,000 net acres with 3D seismic that has helped our production with a limited drilling program and ready to ramp up when the time is right. What's exciting about this area is that we continue to develop exceptional dry gas wells as we described in the earnings release. Following up on that thought, we had a new pad in Lycoming County in the second quarter that averaged 6,086-foot laterals with 31 stages. It's early, but we believe those wells have an average EUR of over 16.5 Bcf each or 2.7 Bcf per thousand-foot of lateral. With an average well cost of approximately $5 million, those wells achieve a return of 151% with a PV-10 of $16 million each. Again, at all the current commercial terms, deducts and strip pricing. The well cost in our Northern Marcellus Shale Division are 27% less than a year ago with 34% longer laterals taking approximately 10% less time to drill. That translates to a 21% decrease in cost per foot drilled. These are outstanding metrics, and my congratulations to the Northern Marcellus Shale Division team. Improvements like these really drive capital efficiency, and I'm confident our team can continue to deliver even more going forward. Before I leave the Marcellus, I've given you 3 great examples of exceptional well performance and economics from both southwest and northeast Pennsylvania, from both wet and dry gas areas. While these 3 pads are better than our average well, I want to make the point that we do believe that these 3 pads represent tangible, repeatable and achievable upside that we can expect to see going forward on a large portion of our acreage. As we drill longer laterals and continue to improve targeting, improve our completion designs and apply new technologies across our Marcellus areas, we believe results like these 3 pads will become more and more prevalent. And as I've often said, while results like these are very impressive, we still don't believe we drilled our best wells yet. For the Mid-continent Division, we remain focused on our continued effort to delineate and test our Mississippian Chat acreage on the Nemaha Ridge, along with developing our St. Louis production in the Texas Panhandle. For the chat, we're continuing with our current completion designs in conjunction with improved geologic targeting. We announced our record oil well, which yielded our highest oil rate to-date in the chat at the last call. To follow-up on that well, over the first 90 days of production, the well has averaged over 400 barrels of oil per day. Additionally, this past quarter, we achieved the highest average IP rate for chat wells turned to sales in any one quarter to-date. While it's still early, the results are encouraging and our expectations for EURs in the chat remains greater than 485 Mboe. Moving to the Southern Appalachian Division. With the recent exchange completed, Range has increased the division's capital budget from $20 million to $40 million by moving the remaining planned capital from Conger to Nora. The division will focus this capital on high rate of return projects that will include drilling vertical tight gas, CBM and horizontal shale wells, along with recompletion of approximately 20 CBM wells designed to target bypass pay. As a side note, there are additional 500 or more candidates just like these. Numerous smaller scale projects are also planned in the short-term to optimize existing production with a very modest capital spend. Over the next 18 months, we plan approximately 50 CBM wells, 30 tight gas vertical wells and about 20 horizontal Huron Shale wells, combined with a total of 75 CBM recompletions and as many as 30 tight gas recompletions. All of these at very attractive and competitive economics with returns up to 100%. The Southern Appalachian team is also introducing some new techniques and well designs resulting in improved well performance. In the second quarter, Range drilled one of its best vertical tight gas wells in over 5 years in Nora. This well has produced at an average rate of 1 million a day for the past 35 days, and we estimate an EUR of 1.5 Bcf for only $430,000, yielding a return of over 100% with a finding cost of $0.30. Again, we own the royalty under a large portion of the field. We also believe there is significant deep potential below the Huron and only a couple of wells in Nora have gone below the Devonian Shale to-date. We estimate that there's an additional 6,000 to 8,000 feet of untested rock below the Huron, and are looking forward to studying that further in the coming years. In the Southern Appalachian region, demand continues to increase with over 3 Bcf a day of new gas-fired electric generation expected to come online over the next 5 years. Nora is strategically located to supply these gas markets in tandem with the Marcellus, allowing us to establish a new and long-term customer base with supporting infrastructure, thereby yielding us a strategic and competitive advantage. The well-defined, large and de-risked inventory of projects, which totals over 5 Tcf of resource potential in the Southern Appalachian Division, coupled with the large gathering system and expanding demand in the region, give us confidence that we can significantly ramp up production in the coming years with economics that are very strong even relative to the Marcellus. On the marketing side of things, the midstream industry recognizes the dramatic volume growth coming from the Marcellus and the Utica plays, and there have been numerous announcements of brownfield reversal and greenfield pipeline projects to move this growing volume from the northeast to other markets. By 2018, it's projected that over 13 Bcf a day of announced projects will be in service. Range is participating in several of these projects, which are designed to move our gas from the northeast directly to the areas that are projecting the increases in demand and prices, especially in the Gulf Coast and southeast regions where -- which are driven by new gas-fired electric generation and expanding petrochemical industry and LNG exports, which alone are expected to represent 6 to 8 Bcf per day of new demand. Also, given that we're the largest liquids producer in the basin with the richest gas, we also continue to actively build our portfolio of liquids contracts and customers while expanding export opportunities and capturing favorable pricing, and we believe our liquids portfolio is one of the very best. In addition to all the great work that our marketing team has accomplished in providing a diverse portfolio of customers and transportation outlooks at some of the best commercial terms in the industry, I want to also congratulate the operating and financial teams for their work in lowering our unit costs by 11%, which is a decrease of $0.41 per Mcfe as compared to last year. This cost discipline is a core value at Range and one that is impactful, and showing up at the bottom line. In closing, we have a great team, a great portfolio of projects and a track record of execution coupled with a great marketing team that has put together a strategy that has optionality, low cost and durability, all of which will help us build shareholder value going forward. Now over to Roger.

Thank you, Ray. From a financial perspective, the second quarter was very successful. We had our production numbers despite 2 unexpected events, our unit costs were reduced significantly. The Nora Conger asset exchange was completed with the teams now substantially integrated. And we strengthened our balance sheet, providing our operating teams a competitive advantage in executing their long-term growth strategies. Second quarter revenue from natural gas, oil and NGL sales, including cash and oil derivatives, was $451 million, 9% higher than last year. Cash margin for the quarter was $2.45 per Mcfe, down 10% from the second quarter of last year, with over 2/3 of the decline due to the nonrecurring top line revenue issues, further described in the earnings release. Second quarter cash flow was $249 million, 10% higher than last year's second quarter, while EBITDAX for the quarter was $292 million, 8% higher than last year. Cash flow per fully diluted share was 9% higher than last year at $1.53 per share. Reported net income for the second quarter was $171 million compared to $144 million in net income from last year. The second quarter of both this year and last year were positively impacted by gains on asset sales. Earnings calculated using the methodology used by most analysts, which excludes asset sales, mark-to-market hedging entries and various nonrecurring items, was $59 million or $0.36 per fully diluted share, up 6% from last year's second quarter. All the GAAP -- non-GAAP measures that I just mentioned are fully reconciled to GAAP on the various supplemental tables that you may find on the Range website. The second quarter continued the positive trend toward lower unit costs in the operating expense categories. Though faced with some tough operating challenges during the quarter, all of the expense categories came in below guidance. Total unit costs in the second quarter, including DD&A, were a full $0.41 below the total unit cost in the second quarter of last year. While a quarterly swing in gas basis of this amount seems to get everyone's attention these days, this $0.41 reduction in unit cost creates enduring value as it demonstrates our continuing operating efficiencies and growing economies of scale in our core areas. The story doesn't end with our cash operating costs. Our capital cost efficiency also continues to improve. The second quarter DD&A rate per Mcfe was $1.33, down 8% from the second quarter of last year and down 41% from 5 years ago. We believe that our capital and operating efficiency will continue to improve while buildings scale on our core areas. And we anticipate our DD&A will decline another $0.03 in the third quarter to approximately $1.30 in Mcfe, followed by yet another step down in the fourth quarter following completion of our year-end reserve report. There was one expense category that was so far below guidance that it merits further explanation. Cash transportation, gathering and compression expense per Mcfe was $0.76 for the quarter compared to guidance of $0.86 to $0.88. As explained on the first quarter call, the reason for the higher second quarter guidance was the cost of additional long-term firm pipeline capacity that was procured in advance of anticipated production volumes. Up to the extent we have firm capacity in excess of our production volumes, and we elect to market this capacity under short-term arrangements, the excess from capacity expense is reclassified to the broker natural gas and marketing expense line, rather than in transportation and gathering expense line. Approximately half of the $0.10 guidance beat in transportation and gathering expense is from the reclassification of this expense from the transportation line to the brokerage line. The other half of the guidance beat was due to actual better perform -- than projected cost performance. Now thanks to the efforts of our marketing team, a significant portion of the excess capacity expense rebooked to the brokerage expense line, was eliminated by remarketing the capacity to others, and we believe that we'll be able to cover this cost in the third quarter until we need the capacity in the future. Now please reference our second quarter earnings release for additional detailed expense item guidance for the upcoming third quarter. The balance sheet was significantly strengthened during the second quarter to $146 million in asset sale proceeds, $171 million in net income and retirement of $300 million in high-cost 8% debt. These actions reduced our debt-to-book capitalization ratio from 57% at year-end to 48%, and our debt-to-EBITDAX ratio from 2.8x to 2.4x at June 30. Our leverage is no longer an outlier for a BB-rated company and we have accomplished our goal of reducing leverage. With annual cash flow projected to increase faster than debt, based on current prices, our debt-to-EBITDAX ratio should decline below 2x within 2 years. And the repositioning of our balance sheet during the second quarter will continue to produce operating performance benefits, such as the multiple long-term natural gas and NGL firm capacity agreements that we announced on June 26. We added additional price protection, including basis hedges during the second quarter, higher production volumes hedge for natural gas, oil and NGLs in 2014, 2015 and 2016. The Range released 10-Q and Investor Relations tables posted in the Range website all contain additional detailed hedge volumes and prices by product. In summary, thanks to the hard work of our people and our diverse portfolio of drilling and marketing options, we were able to hit our production targets in the second quarter, while also lowering our operating and capital unit cost. With the nonrecurring operating issues behind us, we look forward to a second half of the year marked by disciplined production growth, double-digit year-over-year cash flow growth and continued cost structure improvements. Jeff, I'll turn it back to you.

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

[Operator Instructions] Our first question comes from Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, just looking at how the gas mix creeps in the second half of 2014, obviously, some restructuring on your portfolio is contributing to that. But can you talk about how that mix creeps as you tend towards your path of 3 Bcf a day by the end of the decade?

Dave, this is Ray. That's a good question and you nailed it. I mean, the big 2 reasons are: Number one, of course, the asset exchange that we did, Conger for Nora, going forward is going to change the mix significantly. The other thing that's kind of happened in the background more or less is that we've made some really great dry gas wells, and those wells are producing well. The super-rich and wet wells, as we go in longer and longer laterals and making better and better wells, they make an awful lot of gas also. So I think going forward, once you see how this year kind of pans out through the rest of the year, I think directionally that's probably where we'll be for quite a while. I mean, we're certainly going to focus on super-rich and wet. But the thing to remember, I'll pull you back to, is that we've got a great portfolio, and we can choose to go dry, we can choose to go wet or super-rich, northeast PA versus southwest, and we have that optionality going forward. And it's -- they're big areas, core hydrocarbon in place-type areas that give us really attractive economics going forward, and the ability to switch as markets change. David W. Kistler - Simmons & Company International, Research Division: Okay, I appreciate that. And then one of the things you guys outlined in your presentation was you've added a bunch of transportation capacity through 2018. It looks like costs, at least as you guys are outlining, is about $0.39 a nab or MMBtu. Can you talk about that in terms of your view on where you think basis differentials will be on a longer-term basis out of kind of the northeast and southwest? I imagine you think they're going to be wider than that and so I'm just trying to get color around that.

Yes. Hey Dave, this is Chad. Yes, we've tried to -- with the newer slide, we tried to give a little bit more clarity and transparency about our plans to market our gas. We view the regional weakness in the northeast as somewhat temporary. Ray talked about the bidirectional flow projects that are going to by 2018 be in service, about 13 Bcf a day. And once those projects are in service, we think basis in the northeast will form up or settle out a little bit. We don't know exactly where that will be, but I'm going to say probably somewhere well below $1. But when you look at our firm transportation portfolio, we want to get to what we deem to be the stronger markets, Gulf Coast, where LNG exports somewhere between 6 and 8 Bcf a day, in the midwest over the Chicago, Michigan, dawn [ph] areas where, if you look at the forward curves there, they're still relatively strong, NYMEX flat to maybe plus a little bit. So we've layered in these firm transportation arrangements and what we think are really great cheap, relatively cheap cost to these markets that we think, in the years to come, are going to be relatively strong given that demand that we see is there and needs to be served. David W. Kistler - Simmons & Company International, Research Division: I appreciate that clarification. One last one, if I might. You outlined tremendous completion efficiency and drilling efficiency gains. Can you quantify that in terms of the dollars saved over the last year relative to those efficiency gains? And maybe, if you can, put that or juxtapose that to what's happened with dollars absorbed from basis differentials. It seems like there's probably a pretty good offset or maybe even a better offset from these completion efficiency and drilling efficiency gains.

Yes, David. This is Ray. That's a great point. When we look at each year and we do our reviews with the divisions and look at all the different technologies they are trying in frac design, the different things they're doing, you really look at it from 2 sides. You look at it from a well performance side. We try to measure quality and things like EUR per thousand-foot of lateral, and that's not the only thing. But we certainly look at things like that, but we also look at, when we set the budget at the end of one year going into next year, the completions team, for example, will have said, we're going to spend x million dollars completing wells in 2014. I can tell you that we've seen improvements just this year that probably are carving in the range of $40 million to $50 million off of that type of total number. And what we do is basically feed that number back into our capital budget. Basically, they use it to frac more stages, do more wells. It just kind of goes back into the till for that division. And those improvements are substantial, and I think that there's a lot of room going forward like we've seen for it to continue. I think a lot of that is because we've just got an exceptional team. I think a lot of it also is that we're in exceptional rock. We've got the best parameters, porosity, perm, pressures, those kind of things that when targeting makes a big difference when frac designs and connectivity things make a big difference. And so I think, all of that has been great for us in lowering our cost structure, and I think you're beginning to see that in our bottom line numbers as our finding costs keep going down, our unit costs goes down, our LOEs are going down. And then, you factor in going back onto existing pads to drill wells. Like we talked about at the last call, we've actually, I think, added a couple of wells this year as things get tweaked in our schedule. And some of that's almost round off, but one of those wells can save up to $850,000 because of the infrastructure that's already there. The dirt work, the road, the production facility, the watering elements, all of that stuff already being there can save substantial money. And again, you will see that as we optimize going forward, as we drill longer laterals and as we go back in and fill in the infrastructure, that now has some room and as we keep things full. David W. Kistler - Simmons & Company International, Research Division: I appreciate that. Do you think that, in aggregate, that's offsetting any of the challenges on the basis side of things? And as you highlighted, or I guess as was highlighted, that you thought that the basis is temporal and this is structural? If you can kind of just walk us through how those cash flows match up over time. That's really what I'm trying to get at.

Hey Dave, this is Roger. I can take a shot at that. I think you're right. You're absolutely seeing some offset to the basis challenges on the cost and efficiency side. When you look at our unit cost reduction, it's really across the board and more unit cost reductions to come, and particularly the DD&A rate falling like it has. As I mentioned, $0.41 over 5 years, all the dials on the financial dashboard are showing costs going the right direction. So I do agree that you're seeing an offset effect there of cost versus margin.

And I'll just throw in one point. I mean, I think that what we're seeing in capital efficiencies and well performance and all that, that's a really, really long-term step and it's going to continue to get better. So that's what this is for the long. Some of the market things we hope will go away in 3 or 4 years.

The other thing I'll just add in -- and it's all, if you looked on the website, really on Slides 19, 20, 21, 22, 23, that whole section, I think our marketing team has really done an outstanding job. We have a really diverse portfolio that we've talked about. It's really well laid out in those slides, to get us to better price points, to get us to better markets. And it's in conjunction with our plan basically to triple from where we are today, build out that far. So over that timeframe, the unit costs, I think, will continue to get better, the quality wells, capital efficiency will get better. Our portfolio, I think on the marketing side, is better than other people and basins should improve over that time. And we have, since we're a first mover, I think the lowest cost transportation to all those various markets.

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

Jeff, I wonder if I could just touch on one of the prepared remarks that you made about cash flow in 2016 because I assume, and I guess, it's a capital allocation question really. You've introduced some dry gas economics back into your slide deck, and obviously you started to talk a little bit about free cash flow. So I'm just thinking about, what are you signaling to as in terms of allocation of capital longer-term, particularly if you had a success case in the Utica? How should we think about the capital allocation longer-term? And I've got a follow-up, please.

Yes. Well, I think it's important. We have really strong growth and you guys can invest in a number different companies. But I think when you look at our combination of growth, and then literally, by 2016, not that far out there, we think we can get to 20% to 25% growth within cash flow and then do that beyond. So not only can we triple, but we can triple when we have the financial resources to do it and get growth within cash flow. So it's good organic growth. I think we've -- Ray spent time talking about the economics really of all 3 areas, our super-rich, wet and dry. Slide 18 shows you what we have in the southwest, so really strong returns in all 3 areas. And the guys in the northeast have just knocked the ball out of the park with the 16 Bcf wells that cost what -- you're going to be less than $5 million. So even with current differentials, which we expect will improve with time, but even if you take all that into account, we have really strong economics in all areas that gives us confidence to say we can do that. Things like the Utica then become additive. So the good news is a great portfolio, diverse markets going to the southwest, LNG exports, southeast, midwest, Canada and all that. Again, next year looking at on the liquids side, I think we have the best liquids portfolio really of anybody out there on the ethane side. So just -- once Mariner East is up next year, it's greater than a 25% uplift then selling it as gas, net of all transportation fees and everything else. The Utica becomes a lot card and it could be a really positive wildcard. Gas in place mounts [ph] are important. Like Ray said, when you look at gas in place in the Marcellus, it's gas in place is important, but it's also the quality of the rock that you can't see. Quality of the rock you can get to by which your EUR per thousand-foot of lateral and that type of thing. So we think we have that in the Marcellus. When you look at the Utica, potentially we have the same thing in the Utica. We believe that because there's wells that already go through it. The whole thing's covered by 3D. We've already seen the well logs. So we have a good degree of confidence, granted until you test it and put it online, you don't know. So all of a sudden, we think those wells can be really competitive. The higher-quality dry gas wells, and the best wells really in the entire Utica play, are marching east right towards us. And because we have wells on our acreage, which we have confidence that we're, hopefully, we'll see some really good results this year that we can talk about. And then that can become a wildcard, that can even drive further capital efficiencies, it can drive potentially increased growth or it can drive us on a path to 20%, 25% for a longer period of time. 3 Bs [ph] may become 4, may become 5, which is phenomenal. It's the exciting upside when you think about it.

I guess what I'm really trying to get at, you guys have always been very, I guess, disciplined about the kind of 20%, 25% growth rate on a sustainable basis. But I guess what I'm trying to get to is, with the expanding resource opportunity perhaps with the Utica but at the heart of that -- and the free cash flow combination, how should we think about your intention to stay within that kind of guidance range, if you like? Or should you, at some point, do we see you accelerate a little bit into your resource opportunity?

Yes, that's a great question. When we modeled it out, not only do we go free cash flow positive, but it starts throwing off a lot of cash. The really important part is we have the portfolio to reinvest that cash, which could give us a higher growth rate and we'll certainly consider that. It's a great position to be in. We're opportunity-rich, so to the extent we can get better growth within free cash flow with returns that are 80%, 100%, 150%. Clearly, that's something that would probably go right to the top of the list.

Our next question comes from Jon Wolff with ISI Group.

A couple for you. One on the DD&A rate, I know you sort of systematically write-off the acreage each quarter, but do you mark-to-market reserves each quarter and how -- is the dynamic of that kind of run on a quarterly basis or more on an annual basis?

Jon, it's Roger. We perform a full reserve report every year. And during the year, when there's a material change in the reserve deck through either reserve additions or asset sales, we'll go in and Alan's team will work the numbers, and if there's a significant enough change to the rate, we'll go ahead and make that change. So what you saw at mid-year was the drop in the DD&A rate and, again, we'll probably look at the reserves or we will look at it year-end, and then whatever that reserve assessment dictates, we'll roll that result into the fourth quarter. So as I mentioned, I think you'll see that continue to drift downward as we go forward.

Got it. On the unused firm transport or pipeline takeaway, I understand what you're saying around the cost is basically but within a transport line, and then there's some resale. Where does the resale show up? Is that netted out of the price?

On the resale of broker capacity. It's in the brokerage expense line.

Okay. So you're paying a cost for some firm that you're not using, correct?

That's correct. For the -- yes, the second quarter, total costs for unused capacity that was being brokered was $5.3 million and we recovered $2.8 million of it. So going forward in the third quarter, we anticipate we're going to be able to recover all of that.

So is that just netted out of transport?

No. The $2.8 million is in brokered gas revenue and the $5.3 million is -- you'll see embedded in the expense line.

Okay. So could you say that the $0.49 base differential, if you are fully -- if you're selling 100% of gas and FTU, it'll actually be lower?

Jon, this is Chad. Could you repeat the question?

So if your base differential was $0.49 but there was some loss on unused transport, if you're fully using your transport, would the $0.49 differential be lower, just theoretically?

Yes, yes.

And that will happen with time. Sometimes you have to take certain deals as they come along because we know we're going to -- maybe that it's a quarter too early, but it's the stuff [indiscernible] fully using.

Totally got that. And then last one is the quarter-over-quarter lateral lengths seems to have jumped quite a bit and -- like when I talked to you last you were 95% on drilling pads and averaging, I don't know, 3 or 4 wells per pad. Can you update on the big jump in lateral lengths as I see it and sort of how we should think about wells per pad going forward, and how that will help capital productivity?

Yes, Jon, this is Ray. As we go into a year with a plan, the team up in the southern Marcellus and the northern Marcellus division together, they've got wells staked out for the next 3 or 4 years. They've actually got pads located and projected lateral lengths for some of those pads. But as you get closer and closer, we -- our goal is always to drill longer if we can because that's one of the most efficient ways to develop the properties. So as we get closer and closer to those dates where we're going to actually start work on a pad, the land team and the geologic team, the operations team, they will all get together and they'll start figuring out, what if we add this lease here or add this lease there and we can drill 500-foot longer laterals and so forth. And so it's what I call normal blocking and tackling of the drilling plan as we go, and we're going to always be tweaking those and I think you'll see them continue to get longer and longer over the next several years. Remember, we have a really huge position there. And so as we're going in and drilling these new pads, our goal is we've gotten better at targeting and completion designs and we're maintaining our EUR per thousand-foot, as long as we can do all that, our goal is to continue and continue to push these laterals longer and longer going forward.

Last one, sorry for all the questions. Land budget is about 14%, so that's around $200 million roughly. You said it would drop to, did you say 4% or 5% in 2017?

Correct, yes.

Can you give us an update on where you are in terms of percentage of lands held that you want to keep? And how the land budget might evolve in '15 and '16?

Yes, I think you can see that on Slide 10. So basically, as Ray mentioned, on Slide 10, you can see in the southwest -- and really we should update this, it's probably a little old, it's 95% of our acreage is HBP or projected to be drilled under existing lease terms, so it means we have total control. It's probably higher since we've put the flight out. And then basically in the northeast, it's like Ray mentioned, it's because of big releases and have continuous drilling, one rig can hold it. We're in great shape in terms of where we see the big stacked pay potential in the southwest, the 530,000 acres that we think is more like 1.5 million when you consider the Utica and Upper Devonian. And in the northeast now, we have a great phenomenal success in our dry gas drilling.

Our next question comes from Ron Mills with Johnson Writes. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: But one thing that -- especially, this probably maybe on Doug's capital allocation question, when you look at the updated economics for northeast Pennsylvania and how that area now seems to compete with your, not just your southwest dry gas but even some of your wet gas wells, how does that fall into your capital allocation process, and then compare and contrast that with what you're still learning about the Mississippi Chat? On a relative return, it seems like even northeast Pennsylvania looks to exceed that. So how did those 2 pieces fit into your puzzle going forward?

Well, I'd say, one thing when you look at the area, the stuff in the southwest, ultimately, that's the area we ultimately need to drill the hole. And we're, like I said, we're in essence, it's within our existing drilling plans. We're going to hold all that acreage within primary terms. So we want to drill there to finish out holding the acreage. We also want to drill there because of the agreements. And again, we've got some great agreements. Ethane for us next year is a huge uplift. Based on current pricing, it's more than a 25% uplift. Propane netbacks are going to get a lot better starting really early next year with Mariner East. But the advantage of the northeast is the way the leases are set up, we have a lot of control in terms of timing. So we've got great economics, but it comes down to where ultimately, we can move the gas, where we think differentials are going to be and how do we maximize that resource. But when we think of the mid-continent, we really think of -- when you look at the company, we have 1 million net acres in PA, 475,000 in Southern Appalachian Basin and 360,000 or so in the mid-continent. So we have 3 big footprints in 3 areas. The advantage of the mid-continent is there's liquids to it. And there's really 4 plays, I think, or 5 plays that are pretty interesting. One is the Mississippian Chat, one is the St. Louis, and then you have, we have some great potential in horizontal Granite Wash in Cleveland oil on our existing HBP acreage, and a shot at some Woodford. So even in the chat where we are today, when you look at those original wells that we -- the horizontal wells that we did, we’ve got reserves for 485,000 Boe, they still look like they're on track for that. And the new ones, they look like they're on track for that or better. So really all of them look like they're 485,000 or better. Some of them are 600,000, some of them are 700,000 barrels, the individual wells. So in the rates of return, even using 45, we're still 72%. Those are strong returns and low risk, repeatable things. So really, it comes back to portfolio and it allows us that we think to triple from where we are today and maybe beyond with -- maybe even like Doug suggested, accelerated growth in 2016 and beyond. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then secondly, just I guess a subset of the midstream or the marketing side, the asset swap with EQT on the Nora/Haysi, how are you going to be able to utilize that system? Are you going to be able to access places like Cove Point, the Atlantic, southeast Atlantic states, from -- is that just going to be Nora/Haysi gas? Are you going able to get your gas to that system, where there are new projects? Just trying to get a sense as to how -- it seems like there's benefits there, I'm just not fully understanding, I guess, all of the synergies that, that provides.

Yes, Jon, this is Chad. There's a couple of different things it does for us. One, under existing arrangements from transportation that we have, our gas gets dumped in to east Tennessee and east Tennessee connects with the big Transco line that goes up to Station 195, which is at the back door of Cove Point. There's lots of announced and under construction natural gas power generation plants in the state of Virginia. Most of those are right there at our backdoor, so we can access the demand that, that creates. And in the future, obviously, EQM has announced the Mountain Valley project comes down through that area pretty close to us for future marketing arrangements into the mid-atlantic and southeast. So there's current good demand in the area, and we see good future potential as well.

Our last question will be from Neal Dingmann with SunTrust.

So I think this question is maybe for Roger. Just the last [ph] I know there's been a lot of questions asked on realization and -- but, I think you guys mentioned it, it was certainly a bit seasonally weaker-than-normal. But your thoughts as you see going forward, Roger, would you think about putting more different basis hedges there? I mean, not just around obviously gas, but obviously with propane and some of these other markets? I'm wondering, I guess, is there enough volumes -- liquidity on those? Or just, I guess, how you're thinking about perhaps new hedges or incremental hedges going forward, given the realization to the last quarter or two?

Yes, I'm going to defer to Chad on the hedging question. But let me back that a little bit on the first part of your question when we're talking about the realizations. I mean, that's profiled in the press release, cash flow was impacted adversely about $19 million in the quarter due to the nonrecurring events at Mariner West and with the weather issue at Houston III. So I think that needs to be mentioned that those were kind of an extraordinary item hit to the second quarter. And again, that $19 million was a significant number when you look at cash flow per share. Also, when you look at the costs that are coming down, I mean, the positive ground that we made up on the cost side, it reminds me, I guess it's about 3 years ago during Q&A and John Pinkerton was in the room with us, somebody asked John Pinkerton the question about 3 years ago about prices and margins, much like the question you asked. And John answered the question, he said that he saw in the future where our company's DD&A rate per mcfe and their LOE per mcfe needed to be under $2, and it was a great answer. The problem was the quarter he gave that answer, ours was about $2.12. So it's kind of a tough question and a tough answer, but I think he was dead right. And when you look at our recent quarter, when you add our DD&A rate and the LOE, it's like $1.60. So I think, again, hammering on the difference that the low cost structure makes and the big boost that gives you on your margins, irrespective of your hedge deck and your netbacks. So Chad, you want to comment a bit on the hedging side, particularly the bases side?

Yes. So if you -- to start off with, if you look at the NYMEX curve -- the weather, this summer has been 11% cooler than kind of a 10-year norm, so gas burn is way down. So the NYMEX strip has dropped about $0.50. So as NYMEX goes down, the basis in the areas we're selling our gas, if you look at them, it compresses. So we're going to wait. We watch this pretty closely. And if you've noticed over the last quarter or two, we have aggressively hedged our bases as we watch it. So once NYMEX maybe starts moving back up as we move into -- get out of the shoulder season into seasonal demand, winter, as we approach winter, we'll look at those bases and hedge them where we deem necessary.

Yes, Neil, I'd also add, if you look -- you've mentioned liquids, again, if you look on Slide 24 on our deck, I think what, Ray mentioned we're the largest liquids produced in the basin, we have the richest gas. And when you look at, again, the ethane portfolio, I think, it's the best in the industry. It's the second bullet down, better than a hedge, once Mariner East is up, and you look at all 3 things, it's greater than a 25% uplift versus selling the ethane as BTUs and gas. And that fourth bullet down, once Mariner East is up on the propane side -- remember, there's propane and ethane, our netbacks will increase by $0.20 per gallon. So we have some strong things coming up pretty quickly.

Great point, Jeff and as well from Roger. And last, if I could, just one different question on use [ph] obviously. [indiscernible] You've got a lot of acreage potential, besides obviously this upcoming well, your thoughts as far as sort of the best way to tackle that's your type of acreage and then you wait, you certainly have a lot of others that you mentioned during [ph] some other of your acreage around you, so I'm just wondering again how aggressively -- where we maybe see all come out and start drilling there? And I guess how dependent is that on this first well of yours, or is it more dependent on what we'll continue to see from other peers as well as they continue [indiscernible] getting the area?

I think the first well will be really important. We'll have results by the end of the year. We are on track to have that. The beauty of it too is it's stacked pay. So the way our leases are written, any well or any one horizon holds all horizons, so the Marcellus holds it, so to the extent that the well is good, we'll put it online, we'll offset it. And like I mentioned earlier on the call when Doug asked, to the extent we're cash flow positive and we've got prolific wells and we've got excess cash flow to accelerate growth, we'll consider that. So I think we're in great shape.

I was going to say, I'll point out too, that from a what do we do next standpoint on the Utica, we've actually got rim on this particular pad to drill several more wells with long laterals. And the Utica, because of all the information we have and the 3D and the old B passed [ph] in the area and all that news, it's not something where we've got to go step out and delineate. We can actually just go in and manufacture that gas when the time comes. So I think you're going to see really great capital efficiencies. And we believe that if, again, we haven't drilled a well yet and we haven't tested it yet, but if it does what we think it does -- will do, it will compete very favorably with the Marcellus, and that's what we're excited about. And it's 400,000 acres, which I think will be the biggest single position than anybody has.

And it's not just 400,000 acres. It's 400,000 acres of what we think is maximum with hydrocarbon in place. We'll find out shortly what we believe could be really high-quality rock.

So can you just all tie that in right where you're cloning [ph] to get the Marcellus and all the other?

Oh, yes. We'll be able to put that well online.

This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks.

Yes. So our portfolio at range consists of 3 key areas: About 1 million net acres in Pennsylvania, about 475,000 acres in the Southern Appalachian Basin and about 360,000 net acres in the mid-continent. These areas all have the same attributes that we really like at range: Great stacked pay potential, a rich hydrocarbon charge, good infrastructure and great technical, marketing and operating teams focused on creating shareholder value with the assets. It's these assets and this team that gives us the confidence that we can grow at 20% to 25% for many years. As always, we'll stay focused on safely executing our plan and being good stewards of the environment and the communities where we work. Thanks for participating on the call. I know there's multiple other people in the queue for questions. Please follow up with the IR team. Thank you.

Thank you for your participation in today's conference. You may disconnect your lines at this time, and have a great day.