Welcome to the Range Resources Third Quarter 2017 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Statements made during 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. After the speakers' remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, Vice President of Investor Relations at Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range's third quarter earnings call. The speakers on today's call are, Jeff Ventura, Chief Executive Officer; Ray Walker, Chief Operating Officer; and Roger Manny, Chief Financial Officer. Hopefully you've had a chance to review the press release and updated investor presentation that we've posted on our website. We'll be referencing some of those slides this morning. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system. Before we begin, let me also point out that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. In addition, we've posted supplemental tables on our website to assist in the calculation of these non-GAAP measures. The supplemental tables also provide calculated natural gas differentials for the upcoming quarter and detailed hedging information on all products. With that, let me turn the call over to Jeff.

Thank you, Laith, and thanks to everyone joining us on the call today. As we approach the close of 2017, Range is nearing a very important and exciting point in the company's Marcellus development. We are clearly at an inflection point in what has, in essence, been a decade-long commissioning of the largest gas field in the country. Range has been a leader in finding and developing the Marcellus play and now is in a position to capture additional value. Major projects, such as LNG facilities, power plants and the like, have long construction periods of capital-intensive work. For Range, this commissioning phase is nearing an end, with the last of our three natural gas infrastructure commitments slated to come online by early 2018. The culmination of this build-out provides Range substantial deliverability of gas, NGLs and condensate to markets across the U.S. and internationally. This infrastructure will enable us to continue developing our Marcellus inventory in an increasingly capital-efficient manner. The portfolio of takeaway projects that Range has secured over the last decade enables us to move natural gas production of almost 2 Bcf per day to meet our customers' growing demand, both outside and within the Appalachian Basin. The completion of this infrastructure foundation in concert with a high-quality inventory we believe will deliver strong returns on capital for many, many years. For Range specifically, as a result of this infrastructure, we expect continued improvement in our realized natural gas prices as a result of gas transported into higher-priced markets and improved local pricing. Based on strip pricing, we expect that improvement could result in a corporate natural gas differential to Henry Hub of only about minus $0.15, or better, for 2018, offsetting increased transport costs in 2018. We also see positive market conditions on the NGL side…

Thanks, Jeff. Production for the third quarter came in at 1.99 Bcf equivalent per day, which is a little over our guidance of 1.97 Bcf equivalent per day. And guidance for the fourth quarter remains at 2.17 Bcf equivalent per day, resulting in annual growth of 30%. Organically, this represents about 10% year-over-year growth. This expected $200 million a day ramp of new production coming online during the fourth quarter fits well with our anticipated incremental pipeline capacity, expected improving pricing differentials and sets us up well for 2018, consistent with Jeff's description of next year and beyond. Looking at some of the operational highlights for the quarter. We'll start with Appalachia and bring you up to speed on some exceptional well performance from seven different Marcellus pads spread across our acreage position in southwest Pennsylvania. Starting in the super-rich area, we reported a seven-well pad last quarter with an average lateral length of 10,685 feet completed with an average of 54 stages per well. At the time, we reported five of the seven wells were flowing to sales with strong results. The remaining wells were brought to sales in the third quarter, generating an average IP per well for the seven wells of over 30 million cubic feet equivalent per day, or 5,000 BOE per day per well being greater than 70% liquids. These wells continue to be high condensate producers, with the pad producing over 5,000 barrels per day of condensate for over 30 days, which was a main driver behind our 21% quarter-over-quarter increase in condensate production for the company. The wells have been transitioned to permanent production equipment, which by design constrains the wells and, after 90 days of production to sales under these constrained conditions, are performing well above the type curve on a normalized…

Thank you, Ray. In the third quarter, revenues and cash flow were higher than the prior quarter and significantly higher than the third quarter of last year. We hit our marks on production and total costs were in-line with guidance. Natural gas, NGL and oil revenues, including cash-settled derivatives, were $524 million or 47% higher than the third quarter of 2016. Third quarter cash flow was $204 million, 66% higher than last year. Year-to-date cash flow totaled $656 million, a 108% increase from year-to-date 2016. Third quarter EBITDAX was $251 million and year-to-date EBITDAX totaled $794 million. Fully diluted cash flow per share for the third quarter was $0.83, 22% higher than the third quarter of last year. Year-to-date cash flow per fully diluted share was $2.68, 46% higher than year-to-date last year. As cash revenue is growing faster than cash costs, our MCFE cash margin for the third quarter was $1.09, which is in-line with the second quarter and a 33% improvement over the third quarter of last year. With strengthening NGL prices and new pipeline capacity coming on later in the fourth quarter and early next year, we anticipate noteworthy improvement in our cash margins going forward. Net income adjusted for non-cash and non-recurring items, using common analyst methodology, was $12 million, while GAAP net income was a loss of $128 million due to several extraordinary expense items. On the recurring item expense side, direct operating unit cost expense came in $0.02 above guidance due to higher work-over costs, while production taxes came in $0.01 over guidance due to higher-than-anticipated ad valorem and severance taxes, including the Pennsylvania Impact Fee. Other unit costs were below or in-line with guidance. On the non-recurring expense side, we had a bit of noise in the quarter. First, we took $73 million…

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

Thank you, Mr. Ventura. And your first question comes from the line of Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Co. LLC: Morning, guys. Hey, Jeff. Just as you talked about the generalities of 2018, I know you can't talk specifics, but curious if you could just provide a little bit more description by how you may think about capital allocation between the Marcellus and Louisiana and maybe anything that may cause you to change that allocation thought process?

Okay. Great question, Ron. We haven't finalized our 2018 plans yet, but let me try and come at it from a little different angle to see if I can help frame it a little bit. As you know, we have additional firm transportation coming on in Appalachia into 2018. And it makes strong economic sense to utilize as much of that capacity as we can as quickly as possible. A good portion of that capacity, more than half, will be immediately used by simply redirecting volumes out of the current local sales to better markets. Also, we have flexibility in how we can allocate capital. And by allocating additional capital to the Marcellus, we expect to fully utilize the new capacity by the end of next year. To do so will only require corporate growth of approximately 10%. At current strip prices, we believe we can achieve that 10% year-over-year growth while spending less than cash flow. That's a great starting point for 2018 because, theoretically, any increases in commodity prices or proceeds from asset sales could go straight to paying down debt, and we would still fill our new firm capacity. And I'll reiterate that at current strip pricing, spending within cash flow is embedded in our plans going forward. The important thing to note is that we're in a very good position coming into 2018. We feel we're on track in north Louisiana, as you've seen with our recent wells, and we continue to drill phenomenal wells in Pennsylvania with longer laterals. Hopefully, that provides a little context. And we're looking forward to providing a full update later this year or early next year. Ronald E. Mills - Johnson Rice & Co. LLC: And then I just want to follow-up, just as it relates to Louisiana. As your Upper Reds are now tracking your curve, can you provide a little bit more details maybe, Ray, on the Deep Pink and your early thoughts from that well? And how development of that zone could fit into the Upper Red?

Well, sure, Ron. Clearly, that Pink well is the best well in the field to-date from that interval, and we're going to continue to study that. We're definitely making plans to offset it, of course. And I think we'll do some wells in 2018 and 2019 and beyond in that area again. We think there's several cases throughout the field where there's some stacked pay potential like that. It's hard to talk about until we've tested them and fracked them and completed them and so forth, but we're very encouraged with that. We're also very encouraged that the Upper Red wells are right on track. We've got I think 16 more to put online in the fourth quarter that we have really good expectations for. And we look forward to reporting on all of that as we get some of that production history probably at the next call in February. Ronald E. Mills - Johnson Rice & Co. LLC: Great. Thank you so much.

You bet.

Your next question comes from the line of Bob Brackett with Bernstein. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: A quick follow-up on the 2018 capital allocation. You mentioned in some of your prepared comments a focus on dry gas. Is the idea there that gives you the biggest volume to fill that new takeaway capacity?

Well, I think that what I said was I think right now the plans are really early, so this is not formal guidance by any means. But in the current plans that we're putting together, it looks like our mix of dry gas versus liquids and super-rich gas will be slightly higher. But I think that's more of a timing at looking at what's available as far as existing pads to drill on and capacity in the gathering systems at the compressor stations and so forth and so on rather than just trying to optimize. Now, given that everything else is equal, clearly, we would drill the dry gas well to create more volume faster and the economics are still a little bit better there also. So, it's sort of all of that worked in together. But right now, it does look like it will be slightly more dry than next year, but, again, that probably will change. It always does. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay. Gotcha. And then a quick follow-up on north Louisiana. As you move south to Driscoll Field, it looks like that Cotton Valley interval gets awfully thick. Do you think that, number one, are there multiple zones in, say, the Red there? And, two, will the cost of those wells rise? Is it more over-pressured? Any thoughts?

Well, it's a great question, Bob. And, yes, you're exactly right. As you go deeper into the Basin or south of Terryville, we do see a good thickening reservoir. And, in fact, on slide 11 in our presentation is a cross section that illustrates that very fact. You go from a focus on Upper Red in Terryville around 100 Bs per square mile to some of the areas down in Driscoll and around Vernon are close to 400 Bs per square mile. You go from one pretty much identified target in the Upper Red to where the Upper Red down in the southern part of the Basin there might have three targets in it. The Lower Red, Vernon Field is primarily a Lower Red development, so that has about three targets in it. And so, like we talked about on the last call, we've got a couple of vertical tests going and we're going to go slow and be very strategic and thoughtful about what's the best way to approach these fault blocks, but, again, we're very encouraged. We've announced another encouraging result in this new fault block to the north of Driscoll Field, so we've got three fault blocks now that look very encouraging and we're going to look forward about talking about the results of some more tests in those wells as we get into next year. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Thank you.

Your next question comes from the line of Neal Dingmann from SunTrust.

Good morning, guys. And just looking, Jeff, at that slide on page nine, obviously, some fantastic results, particularly on those two in the four-well pad, over 41 a day, and then that four-well pad over 40 a day. I see the lateral lengths there. Can you talk about, is there anything else special on those wells that, as far as the surfactant, or just the fluid that you did on those, those obviously, stuck out a little bit. I didn't know if you had any more color around those.

Yeah. Neal, this is Ray. And I'll fill in that one and Jeff can add some color, too, or Alan. But, clearly, I think the biggest change is that we've continue to optimize our reservoir models and we continue to look at things like targeting, cluster, perforation cluster placement, the amount of proppant that we're putting in there, fluid, injection rates. Again, we present to the public three type curves: super-rich, wet and dry. But the reservoir team up there and the completions team has about 30 different models that they're working on at any one given time. So I think it's just a refinement of that. I think another big influence, really, really big influence, over the last three, four years, has been basically, as we've incorporated the Big Data analytics and starting to look at a whole slew of different variables and using machine learning. And what's important is, taking that machine learning and then doing predictive analysis with it and doing some things that weren't necessarily apparent to an old frac engineer like me, for instance, things that were totally different. And clearly, it's paying off. If you go back and look at my remarks in the last conference call where I talked about we had some areas that were over 4 Bs per 1,000-foot, clearly all these wells we just talked about. And the slides that illustrate the fact that it's across the whole position; it's not just any one particular area. And we literally do have thousands more of these to do and the lateral lengths are getting longer and the teams are getting better and we're using more predictive analysis in analytics and so forth. And so, I think this is a trend you're going to continue to see and we look forward to updating all these economics and curves and costs and everything, like we always do about first of the year, so I think we'll come out with that probably in February. And we're pretty excited about what we see going forward. The economics are looking really, really good. And I think it's a great timing, like Jeff talked about in his remarks, that we're at that point where all of these big projects are reaching commissioning. We said we don't have any more big projects coming online. We believe there's going to be a very viable market there locally and we're going to be able to take advantage of that. And I think is a strategy that we've been 10 years putting together and it's coming to fruition. And I'm, for one, really glad to see it.

And just add a little bit. I think Ray and Dennis and really the entire team that we have working on that technically are just doing a great job of continuing to drive performance up. But the other thing at a higher level, and just – and Ray said it, but it's an important point when you look at that slide on page nine, we have a big blocky position in the core part of the play. And there's a lot of advantages to that, and particularly now that we have all that infrastructure in place. It just demonstrates, that slide, coupled with where we've been trending over time that that position is high-quality across northeast, southwest and the center part of it. We have a big blocky position that enables us to continue to drill longer laterals, continue to drive efficiencies and experiment. And, again, Ray said it earlier, we think the cores of these plays are defined. And the key is what company has core, and you're going to start at some point to see that sweet spot exhaustion. Range will have plenty of inventory to drive well beyond that and to continue to drive efficiencies.

One more point I wanted to just emphasize again is the pad number five on that map is a pad right by the Houston plant. For those of you that have followed us for a long time, the Discovery Marcellus well was basically right by the Houston plant there. And, of course, we built some of those early systems there. And those wells have been really good from decades – from a decade ago, and that system has been packed for years without the ability to add anything to it. That pad has been online for 180 days and it's almost 80% above the type curve on a normalized basis. And if you look at the IPs, it stacks up well and it's a 30% shorter lateral on average than most of the other ones in there. So we're really, really excited about the potential locations that we see going forward. And I think that's a great example that we don't want to over gloss it.

Great details, guys. And then just one follow-up if I could. Ray, you and Roger mentioned about, obviously, the focus on getting that debt down to about 3 times and getting it to investment-grade. Being cognizant of not having that 2018 plan out there, would that entail trying to get to that – I'm just trying to look at the general overall activity with given prices today, given your hedges and given the plant capacity coming on. Would that mean would you potentially accelerate or think about going the other way as far as trying to bring that leverage in line?

Let me start. But when would you look at leverage, and, in fact, that might have been noticed that I gave originally and then the answer to Ron's question initially, the important part is we think to fill pipes requires approximately 10% growth, which we think we can do at current strip price. And we can do that, get 10% year-over-year growth, spending less than cash flow. In addition to that, we have active asset sale underway. So it's really a combination of those two things, of that asset sales coupled with the ability to fill pipes and get growth below cash flow that would drive delevering. The pace of that then depends on where oil and gas prices and liquids prices end up coupled with the speed of the asset sales. And we know with asset sales it's important to find the right buyer, to be patient. It was important for us in Nora. And sometimes it's hard to predict that exact timing, but we have those things in place and the ability to do that.

Thanks, Jeff. Thanks, guys.

Thank you.

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

Thank you, folks. Good morning. Just wanted to revisit your remarks on transport costs and the commissioning phase coming to an end here. When exactly do transport costs peak at $1.20 per M? And what's the progression in unit costs from that point forward? Asking really in an effort to get a better sense of whether the capacity additions are truly a competitive advantage here and what that means for margins and recycle ratios going forward.

Dan, this is Laith. Looking at the transport costs, that will peak at a time when Rover comps on. So if you're looking at that being sometime in the first quarter, it would peak around first or second quarter. And then how quickly we drive that down will simply be dependent on the growth numbers that we've got for 2018, which we'll come out with probably early next year. But it sets us up really well, like Ray had mentioned, it gets 70% of our gas headed to the Gulf Coast. And you start to see the benefit of that additional transport really in the fourth quarter. And our fourth quarter differentials improve to $0.28 from $0.51, which we saw in the third quarter. And then looking forward into next year, it improves further to $0.15. So, a massive improvement in differentials, which, to your point, serves to offset that increased transport.

Okay. Thanks. I appreciate the answer there. North Louisiana DNC costs, a question on that. Wild Horse WRD as well as MRD, that was acquired, stated completed well costs well above the $7.4 million that the company now estimates. What explains the difference in your view? That is, are there any above-ground costs not included in your estimate? Or if the comparison is really apples-to-apples, then what inefficiencies do you think have been squeezed out since taking over operations that would explain the lower costs here?

Well, it's a great question. And I think when we first looked at the deal, over a year ago, it was at $11.3 million, or I can't remember exactly, but over $11 million well cost. And we predicted early on we could get down to $8.7 million, close to $8 million I think in the acquisition, S-4, or whatever it's called. And essentially, we've been able to get it down to $7.4 million for a 7,500-foot lateral. I think a lot of that is people. We brought on board Scott Chesebro, who has a world of experience in high-temperature high-pressure drilling and has optimized some big drilling programs for some big operators in a lot of different basins. So it was a big focus on changing out the team and the people. It was a big focus on implementing some new technologies, new motors, new bits, new mud systems. A lot of that on the drilling side. And then the completion side, I would say was more just getting back to a point where – we just do it different than a lot of them do. We weren't necessarily focused on 30-day IPs and pullback procedures similar to what they had done. So we're doing things differently. I think we're approaching the stimulation designs in execution, especially more like we do in Appalachia, 24/7 operations and a lot of different things like that. So I think it's just an overall different long-term approach, much more focused on trying to smooth out the activity level. You can do a much better job when you have a frac crew working for you continuously, rather than bringing them in for two or three weeks and then letting them go for two months and then bringing them back and so forth and so on. And I said early on when we announced the deal that we would really be going into 2018 before we could kind of smooth it out and do it "the Range way." And that's really where we are. I think we'll be moving into next year. What's important right now is that we've got three frac crews running. We've basically got them fired up just in the last week or two. Everything's right on track in north Louisiana. Third quarter looked good, we just didn't put very many wells online. And so I think we're pretty pleased with what we see going forward there.

Okay. Appreciate it. And one last one maybe here just on asset divestitures. What more can you tell us about the contemplated divestitures of the Mid-Con and northeast PA assets, in particular timing? And use of proceeds here? Guessing that it goes right to the balance sheet.

Yeah, use of proceeds to the balance sheet. We have active processes underway. We're actively working on divesting in the Mid-Continent as well as northeast PA. And like I said in my prepared remarks, we'd also consider – we've got a big acreage position in Pennsylvania, 900,000 surface acres. And in some of those stacked pay areas, if you just look at southwest PA, 1.5 million net acres when you consider not just Marcellus, but Upper Devonian and Utica. So we have the Mid-Continent, we have northeast PA. And then to the extent somebody is willing to pay us what we think is a good value for something we're not going to get to for a while and pull some of that value forward, we'd consider that as well.

Got it. Appreciate it. Have a great day. Thank you.

Thank you.

Thank you.

Your next question comes from the line of Bob Morris with Citi.

Thank you. You had mentioned that to fill the total capacity by year end next year in the northeast, that would imply corporate growth of 10%. In that 10% corporate growth, what does that imply for the Terryville growth for Louisiana?

Again, by late this year and early next year, we'll give actual more distinct guidance. But what we're saying is, this year, we allocated about two-thirds of our capital to PA and about a third to north Louisiana. We expect good results and we're having good results in both areas. But given the new pipes coming on, we'll probably over-allocate capital to the Marcellus. Use some of that north Louisiana cash flow – again, the advantage of having two areas – to help fill pipes. So the growth would be disproportionate to PA next year, because we'll be allocating more capital there. We'll give you more color late this year most likely, early next year, which is our typical timeframe for coming out with the budget.

Okay. And then in the Terryville Field in north Louisiana you took some write-offs for acreage you expect will expire. How many rigs do you need to keep running there to hold the acreage you now anticipate going forward in 2018? I think you're running, is it two or three frac crews and then how many rigs now? And how many do you need to average next year to then hold the acreage and not incur any further write-down on expirations?

Sure, Bob. I'll see if I can hit all those points. I think in Terryville this year, we'll probably average around five rigs. We've had up to three frac crews at different periods. But, again, they've kind of been in compressed timeframes when it's happened. So right now, currently I think we have five rigs running right now. We have three frac crews running there. I do know that for a fact. I think next year it will – like Jeff was alluding to, I think it's probably a little less than that. And hopefully we're at more of a steady pace for frac crews, where we would average something around one crew running most of the year, but probably not all year. Appalachia activity will probably be similar to now, if not a little more. Again, we're just formalizing those plans right now. And we'll come out with formal guidance in late this year or early next year, but that's kind of where we see it right now.

Yeah, Bob, this is Roger. Yeah. The expirations, again, we're taking these impairments ahead of the expirations, so these haven't actually expired. So we have a lot of optionality going forward if the drilling results or whatever changes our direction of capital. But I would point out that when it comes to acreage, when you look at our proxy peer group, there's four of our peers that have market caps higher than Range whose total acreage positions are less than what we have in north Louisiana. So we have plenty of acreage there to move the needle for us. We're not at all concerned about that.

Sure. I understand that. I was just wondering how many rigs you needed just to hold what you do anticipate not expiring there, but that's good. And then I guess just one last quick question. You said that the frac crew showed up couple of weeks late. Is that any indication that the results of just tightness in the market and that crew having to come from, say, some other place like the Permian? Or is it other factors that caused that to be late?

Yeah, there's no doubt that the activity levels were up and there's a lot of tightness. There's crews that have probably left from every basin that have hauled on to West Texas, New Mexico, over the last months. Don't expect that's going to change a whole lot. Right now, we're going through the process of putting prices together and bids and awarding contracts. And that will happen for us over the next 30 days or 60 days or so. That's part of putting our formalized plan together to present to the board in December and so forth and so on. So I think it's definitely indication of that. And that's simply what it was, the frac crew just tied up for another operator longer than we thought and didn't get to us as quickly as we had thought when we talked about it 90 days ago. As you know, in this business things change a lot in 90 days oftentimes.

Yeah, great. Thank you.

All right. Thanks.

We are nearing the end of today's conference. We will go to David Deckelbaum with KeyBanc for our final question.

Just under the wire here. Thanks, guys. I guess I'll round out the call with maybe more of a philosophical conversation. Jeff, I wanted to understand a little bit more around your comments. Once you fill the 900 million of incremental pipe capacity coming out of Appalachia, you said a couple things. One, you want to stay below 3 times levered. But, two, that you're going to be focusing more on perhaps under spending cash flows at that point and continuing to delever. I guess should we think about it beyond 2018 for Range, that the philosophy will be just to hold that full capacity steady unless commodities would dictate otherwise, where you'd want to significantly start ramping up capacity? At that point, should we just be thinking there's obviously the in-Basin option to accelerate. But is the long-term plan here once you get to that full capacity on pipelines to start harvesting some free cash as opposed to even considering growth beyond that full capacity?

I think the key is, one, again, we'll come out late this year, early next year, with our 2018 plans and maybe a little clearer vision past that. But the important part is I think we're in a great position and we have great flexibility. Again, to fill the pipes next year, 10% year-over-year growth, we can do that for less than cash flow at strip pricing. And when you look forward then, we have a lot of flexibility with no new projects coming on. Like Ray said, there's 13 Bs of additional pipeline capacity coming in just to the southwest part of the play over the next couple of years. So, we think there's plenty of availability either to sell product in-Basin, which will help reduce and drive down our unit costs that way, or perhaps to pick some of that up and move it to better markets. But because of the high-quality position, peer-leading or one of the best recycle ratios in the business for an oil or gas company, we think we're in a great position with a lot of flexibility.

Okay. I appreciate that. And then the comments around perhaps bringing the value forward outside of non-core assets I guess within the core. Are you considering some pruning within the core of outright sales? Or are you also considering developmental JVs or is it everything is on the table to try to maximize MPV?

Yeah, I think what we're saying is we are open and we're open-minded to what that would be. Of course, we've got the asset sales in the Mid-Continent, northeast PA. But to the extent there's some method or some opportunity out there to pull value forward, we'd certainly be open to that.

Thanks, guys. And best of luck in Q4.

Thank you.

Thank you.

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

I just want to say we really appreciate everybody taking time to be on the call with us this morning. Feel free to follow-up with Laith and the rest of the team with any additional comments you might have. Thank you.

Thank you for participating in today's conference. You may now disconnect at this time.