Welcome to the Range Resources Third Quarter 2016 Earnings Conference Call. This call is being recorded. All lines have been placed on mute to prevent any background noise. 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. 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, 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 the 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 posted on our website. 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 and to provide more details on both natural gas and NGL pricing. With that, let me turn the call over to Jeff.

Thank you, Laith. We are excited that we closed our merger with Memorial on September 16. The integration of the teams and the assets is going very well. Range now is a better, stronger company with strong teams and high quality assets in both our Marcellus Shale division and the new North Louisiana division. I'll begin by reviewing what Range accomplished during the quarter, and then I'll discuss some of the key attributes we have that I believe set us up for success. Range's ability to consistently drill low cost, high return wells across our acreage in the Marcellus as well as focus on driving down unit costs resulted in solid operating results for the third quarter. And due to the closing date, 15 days of solid performance from the North Louisiana team were represented in the quarterly numbers. The third quarter took us one step closer to seeing meaningful improvements in realized prices across all of our products. First, all three of our liquids projects were on line during the quarter: ATEX, Mariner West and Mariner East. We sold ethane to Europe, Canada and to the Gulf Coast, and exported propane from Marcus Hook into international markets. The net effect is that our NGL price increased from 13% of WTI to 25% of WTI on a year-over-year basis. Second, we have a new condensate sales agreement which – agreements, which commenced on July 1. These agreements improved our corporate condensate realizations from a $13 differential to WTI, to a $6 differential to WTI on a year-over-year basis, in a similar improvement compared to the second quarter of this year. Third, NYMEX gas prices were higher in the third quarter, and all of the gas pipelines we are contracted on are expected to be on schedule. This includes Spectra's Gulf…

Thanks, Jeff. We continue to execute in the Marcellus and are already achieving significant wins in North Louisiana. Production for the third quarter came in at 1.51 Bcf equivalent per day, and for the fourth quarter, we're setting guidance at 1.85 Bcf equivalent per day. Excluding the asset sales and the North Louisiana volumes, we expect to grow 10% over last year, as previously guided, while maintaining our capital expenditure level at approximately $495 million. And importantly, we plan to end 2016 with an exit rate higher than last year, setting us up well for 2017 and beyond. We continue to make great strides in unit cost reductions, and this is something that we're really proud of. Specifically driving this improvement, in the Southern Marcellus, we've seen a 35% reduction in LOE year-to-date versus the average for 2015. This was achieved through three key areas: one, leveraging service cost with our long-term vendor relationships; two, reductions in third-party manpower; and three, the savings associated with our water handling through our water logistics team, which gets water from our production pads to our frac operation quicker than ever. Staying with our Marcellus activity, capital efficiency continues to improve, and I'll review some examples from our operations in Southwest Pennsylvania. On the water front, we've continued the improvements that we discussed on the last call, and we'll reduce our capital expenditures for water by over $20 million this year. We've reduced the total average completion cost per foot of lateral by 20% as compared to last year. Our top three pads completed in 2016 have averaged over 8.5 stages a day for a total of 432 stages. The best pad achieved a completion cost per foot of almost 23% below the average, which again was already 20% lower than last year. We're…

Thank you, Ray. I'm delighted to report the third quarter of 2016 is the quarter we have been waiting to talk about for a long time. Natural gas, NGL and oil sales before cash-settled derivatives was $304 million. That's 36% higher than the second quarter of this year. Cash flow at $123 million was 32% higher. EBITDAX at $160 million was 24% higher. And cash margin at $0.82 was 17% higher. Range has navigated this period of low commodity prices well. And by all measures, the third quarter of 2016 appears to mark a financial turning point for Range. Given that the third quarter includes only 15 days of operating results from the Memorial merger, we're excited that we have not only turned the proverbial corner but are now moving forward on a wider, unique and more prosperous new road. The reasons for our optimism and confidence in Range's path are multifold. We have attractive new optionality when deploying capital, production continues to steadily grow, the cost structure continues to improve, and the higher margin marketing and transportation arrangements we've spoken of in prior quarters are now fully operational, delivering the improved cash flow and margins we predicted. Year-to-date cash flow was $316 million, and year-to-date EBITDAX was $424 million. Fully diluted cash flow per share this quarter, which again includes only 15 days of cash flow from the Memorial merger, was $0.68 per share. Looking closer a the third quarter cost structure performance, the Range teams have continued to do a terrific job holding the line on cash direct operating expense, which at $0.16 per mcfe was roughly the same as last quarter and a 38% improvement from the third quarter of last year. All other unit cost items came in at or favorable to guidance, with the exception…

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

Thank you, Mr. Ventura. The question-and-answer session will now begin. And it looks like our first question comes from Arun Jayaram from JPMorgan.

Gentlemen (33:12), my first question is just your broad thoughts on capital allocation between the Marcellus and Northern Louisiana as you think about 2017 and 2018. I think you're running four rigs in Terryville right now. So how are you thinking about capital allocation? I also wanted to see if you could maybe comment – I do know that MRD had some under-delivery on the PennTex systems. So that could provide an outlet for some kind of value-added growth thinking about the MVC's there.

Yeah. It's a good question. Again, I want to stress, when you look at 2017, we're projecting an organic growth rate of 11% to 13%. And really, that's an output from several different scenarios where we're allocating various percentages of capital between the Marcellus and North Louisiana. Again, I think it's a great question and a really important one because it highlights our ability to choose between two great assets, each near key market areas in the Northeast and in the Gulf Coast. Both areas we have the ability to ramp production and are expected to get good growth next year relative to 2016. And we can do that for a long time into the future. Another key thing, I think that's kind of a unique ability we have to react to upcoming changes in capital allocation, in my opinion, is a real advantage that Range has that other companies don't have, or a lot of peers don't have. So it's a function of several things. We've run multiple scenarios. And you're right, Arun, we think as we continue to grow and ramp volumes, which we expect to do in North Louisiana, that, that cost that you mentioned will come down significantly. With time, we can really drive down the processing and gathering costs.

Okay. And just my follow-up, some intriguing comments just on capital efficiency gains in the Marcellus from longer laterals and using existing pads. Can you calibrate, perhaps, I don't know, on a percentage basis what that could do for your Marcellus program in terms of just capital efficiency in 2017 and 2018?

Yeah. When you look at the pads, we've got 230 existing pads out there. And I won't quote those numbers again that I went through in my remarks, but all of them represent tons and tons of opportunities to go back and drill laterals. We've literally got thousands of them we can do. With the infrastructure in place, of course, when you go back onto an existing pad, you don't have to build the pad, the road, meter taps, production facilities, the water infrastructure, all that stuff is already there. And you can see savings on a per well basis ranging from $200,000 up to – I mean there's one example in our presentation, for example, that's $850,000. And they're not all going to be $850,000, they're not all going to be $200,000. I think every case is going to be specific. But as we roll into 2017 and we see as much as a third of our wells potentially next year in our current plans today which, of course, will change, but when we look at it today, we see maybe a third of our wells next year on existing pads. That could move to as high as half of our wells potentially in 2018. And I think over time, you're going to see some major improvements to capital efficiency. But I would peg it, if you try to get back to a well-by-well basis, somewhere between that $200,000 to $400,000, $500,000 per well on average. Something like that.

Great. And then you're also going to be drilling longer laterals as well, right?

Yes. Yeah, we do expect...

Can you remind me of the average lateral length in 2016?

In 2016, I think our average drilled lateral length is probably around 7,000 feet or so. Next year we'll see that going up to 8,000 feet. Of course, our goal, like I've said in the past, is to continue to push those longer and longer. We believe in the liquids-rich areas, the wet and the super-rich, that around 8,000 feet might be optimum for us. In the dry, we see them closer to 10,000 feet on average as we drill into the future. Now, of course, the wells that we turn into line may be a little bit less length than the ones that we're actually drilling because remember, again, you just got the lag time of six, nine months to a year, in some cases, before the wells actually come on line. But they'll be stepping up right behind it year-over-year, getting longer just like the wells we're drilling.

Okay. Thanks a lot.

Thank you.

Our next question is from Pearce Hammond of Simmons Piper Jaffray.

Morning. And thanks for the helpful disclosure on 2017 and 2018 production growth. What would CapEx be roughly to drive that production growth?

At or near cash flow.

And then, Jeff, what are you seeing on service costs on a leading edge basis? And what is your expectation for service costs inflation, if any, in 2017? And are you taking any steps to mitigate any of this potential inflation through maybe longer term contracts?

Yeah, Pierce. This is Ray. I'll tackle that. It's a great question. And clearly, we are at or near bottom, we think, in service prices, and I don't think anybody would disagree with that. I think that the way prices on the service and supply side move from this point forward depends on – it's going to be very regional, I'll say it that way. I think in areas potentially like West Texas and maybe the SCOOP/STACK areas and places like that where activity seems to have ramped up quite a bit more, you know you could see prices moving up. In the Marcellus, per se, we don't see it. We are entering into what we term long-term relationships, not necessarily contracts. I think contracts is a term that gets way over-used when talking about service companies because every contract's different and has different outs and different resets and you know everything else that people put in there. But we focus a lot on long-term relationships and we don't see any important or significant price increases going into 2017. It's a little hard to see past that yet because I think a lot of it depends on commodity prices and what we see there, and we're pretty excited about the future going forward. We've got two great plays. We can allocate capital freely back and forth between the two plays. We have organizations and opportunities in place to significantly ramp up both sides of that. And so I think that we have a ton of really high-class opportunities going forward, and I think we're going to be well positioned to adjust to whatever happens on the service side.

Thanks, guys, and congrats on a great quarter.

Thanks.

Our next question comes from the line of Doug Leggate with Bank of America. Doug Leggate - Bank of America / Merrill Lynch: Good morning, everybody, and thanks for the early look at the next couple of years. Ray, I guess – well, maybe Jeff wants to answer this – but I guess the question we're all trying to figure out is the returns on Terryville look like they're, on an apples-for-apples basis, better than the returns marginally in the Marcellus, given the differential challenges and so on. I realize you talked a little about allocation and relative rig counts, but how do you think about how far you would want to go in skewing the capital towards Terryville? Why wouldn't you go to the highest return assets in the portfolio now that you have that option?

Doug, I'd say if you look at the returns that are in our IR presentation on the website, and you look at them, they're actually close. Terryville was slightly better but they're very close. And one of the advantages we have again that a lot of our peers don't have, that are single-based and are focused is we can allocate capital back and forth. So as best as we can on a real-time basis, we'll be looking at making the best investment decisions we can. But we think that's an advantage we have that others don't. Doug Leggate - Bank of America / Merrill Lynch: I guess I was thinking more about the impact on basis differentials in terms of mix, Jeff. We've seen (42:19)

Sure, I mean – yeah, right. And we have... Doug Leggate - Bank of America / Merrill Lynch: (42:22)

The economics that are in there reflect the current strip and basis differentials for both areas, and yet the returns in those areas are close. To the extent that changes, we'll do our best to allocate to maximize value. Doug Leggate - Bank of America / Merrill Lynch: Great. Thanks for that. My follow up is hopefully a quick one. It's really on the condensate pricing improvement. I know you touched on this last quarter, but I'm just trying to understand, if you could walk us through to the – notwithstanding any confidentialities – how you were able to achieve a $7 bump in your realizations and whether that is sustainable going forward, and I'll leave it there. Thanks.

Doug, yeah. This is Chad Stephens. It's really a function of the purchaser has a lot of scale in the area, and they have some new assets that they needed feedstock for. And fortunately, our light crude serves the asset that they just put in service well, so it was a good fit. Doug Leggate - Bank of America / Merrill Lynch: So it is sustainable going forward?

Yes. Doug Leggate - Bank of America / Merrill Lynch: Great stuff. Well, I'll see you in a couple of weeks, guys. Thanks so much.

Thank you.

Thank you.

Our next question comes from Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Co. LLC: Good morning, guys. Question on the extension areas of the Terryville field. Thanks for the cross-section showing the depth and the thickness, improving on the southern extension areas. The three extension tests, Jeff, you mentioned were spread across your position between the Driscoll/Vernon type areas or along that cross-section. Where about are you testing those extension areas?

We haven't specifically disclosed where they are. That being said, I've seen different – I mean it's public data – and I've seen some people spot them up already. But I think the important part is, Ron, is – the point that you're making – is that they're far away from Terryville towards the southern edge, far apart from each other. So they're good tests of the 220,000 net acres, to start to look at what does the other acreage look like. The cross-section reflects the upside, and as you go south, it gets thicker. And as Ray mentioned, there's multiple fields in the area, plus 50 vertical wells across the acreage. It kind of gives you a feel for what that potential is. And, based on the – Ray mentioned with some detail, actually, not just say (45:08) they were encouraging, Ray gave you some feel to direct comparison back to Terryville in terms of the amount of gas in place and thickness and quality of the reservoir. But/and still we have – till you get the long-term tests, you don't know, but we're certainly encouraged by what we see, both the quality, quantity and where they're located. Ronald E. Mills - Johnson Rice & Co. LLC: And is it fair to assume that – were these wells drilled with your design, with your lateral targeting? Just trying to get a sense as to the initial results, how they will be drilled versus what your plans are in terms of lateral targeting.

Yeah, Ron. I mean, the wells were cited by the Memorial team prior to Range really being involved. I mean, we were there but we weren't really in control at that point. And as far as picking the actual targets, where we put the horizontal laterals into, that was a real team decision and Range was very much driving the train and working with the Memorial team in that, and fully baked in, fully supportive of what they picked and we all agreed to that up front. So yeah, so we were heavily involved in the completions, and of course, the completion design is on our watch and we're executing those as we speak. Ronald E. Mills - Johnson Rice & Co. LLC: Perfect. And one last one in South Louisiana. Ray, the well you highlighted that came in about – it looks like it's almost 15% or 20% above the type curve you had used to evaluate the deal. I assume that well was drilled prior to the merger. I guess that's question number one. And the second part of that is what drove that outperformance, especially if it didn't have the benefit of such tight lateral targeting?

Yes, Ron, this is Alan. The well was completed prior to us taking over operations on it. Probably what drove the productivity of the well is the fact that it was completed 100% within the 100 foot target interval. So it was – just to kind of help put some color on this thing, it's a 4,700 foot lateral. So the 30-day IP, if you normalize it, would be 43 million cubic feet equivalent a day. That's why it's very impressive. So was it 100% within the target interval? Obviously, completion design continues to change over time, so some modifications were made there. Ronald E. Mills - Johnson Rice & Co. LLC: Great. Thank you so much.

Our next question comes from the line of Jon Wolff of Jefferies.

Hi, guys.

Hey, Jon.

Very intrigued by the 230 existing well pads in Southwest PA you've talked about a little bit in the past. And I think you said a third of drilling would be on existing pads and 50% next year. Can you take us back in history? I recall that number being like 10%, 15% only a year or two ago. And then you went a little fast, was wondering if you could repeat the numbers of how many wells were sitting on each of those. I think you said 69 wells, 70 wells that had five or six wells on them. Could you go through that again?

Sure. Sure. 230 existing pads. Those are all new pads and pads that are in various stages of execution. There's 124 pads with five or fewer wells. And there's 59 pads with six to nine wells. In general, most of our pads have the capability of eventually 18 to 20 wells. So you can do the quick math there and, literally, there's thousands of that. It's page 19 in our new presentation on the website.

Those are Marcellus wells?

Well, those are just...

To get to 18 to 20?

Yeah, the existing wells are Marcellus wells.

To get to 18 to 20?

The future wells could literally be in any formation.

Okay.

Because again, eventually, we could be putting Utica wells in there and Upper Devonian also if we chose to, going forward. But there's literally thousands of Marcellus wells left by itself.

Okay. And then going back in time.

Yeah. Going back in time, we have, of course, been experimenting with going back on existing pads for years now. And, in fact, there's an example in the presentation that has got about over two years of production history on it. And it was a pad that we went on to a five well pad and put two additional wells on it. And we were wanting to answer three questions. One, how much money did we actually save? Number two, did the wells interfere with the existing wells that were already there? And then number three, since we were going onto a pad that was already two years old, with the better targeting and the better completion designs, in other words, two more years of learnings, would that really help the completion? And the answer was, as presented on that slide, we saved $850,000 per well, which is huge. The wells did not impact the existing target. And literally, the new wells were, literally, only targeted about 20 feet or 30 feet different from the original wells. So even in the same zone, which is only about 80 feet or 90 feet thick in that area, we were only about 20 feet apart in difference and we were 700 feet between wells and we did not impact the existing wells. So that was a huge learning for us and we've repeated that several times since. And then the third thing is the wells, after two years of production, were 53% better producers than the original wells. So you can start to imagine, if you just go through that hundreds of times, going forward in the future, you can start seeing what sort of capital efficiencies you could bake into that, and it's pretty impressive. So we've literally got a lot of that to do. I think a year or so ago, we were about 10% on existing pads. This year, I think we're probably less than that, hardly any on existing pads. Another important thing that's happened this year is we have all our HBP concerns are finished. So literally, we have no more acreage at risk and so we no longer have to worry about that aspect, which allows us to, going forward, really focus our capital in the very best returns. And that's what you're going to see us doing going forward. And I think you'll see those numbers gradually increase. I don't think it will ever be a 100% because, clearly, we've got some really good areas like in the eastern part of Washington County in our dry acreage, where even a grass roots, brand new, four well pad there has even got better economics than going back onto an existing wet or super-rich pad. So I think it allows us, real-time, to allocate capital to the very best projects in the Marcellus. And then now, of course, we've got another world-class asset, North Louisiana, that gives us another great option.

And then just thinking about allocated costs, pad is somewhere $1.5 million to $2 million?

Yeah, pads can be anywhere from $1 million to $2 million. Roads can be significant to insignificant, just depending on how long they have to be. Production facilities can be several hundred thousand dollars per well on the initial install. Meter taps can be pretty expensive and then water infrastructure is super expensive.

(53:38).

Jon, we have a lot of people queued up for questions. I hate to say it, but just to try to get a couple more questions out, I don't want to cut you off, but see if we can get at least – there's a bunch of people we aren't going to get to, but maybe we can get a couple more. Next question?

Thank you. Our next question comes from the line of Mike Kelly of Seaport Global.

Appreciate that, thanks. Jeff, hoping to get your thoughts pertaining to the 20% growth figure you laid out for 2018. On our model, we could get there just adding a couple rigs, and I'm curious, given the bullish macro backdrop you laid out, great liquidity, great economics at $3 gas, if you're tempted to push that growth rate maybe meaningfully higher, and wanted to gauge your willingness to outspend to get there. Thanks.

Yeah, I think an important part is, we're saying we can get that kind of growth, which is great, 20% at or near cash flow with $3.25 and $60. Clearly, we have a large inventory – multi-year inventories in two really high quality areas in Pennsylvania and in North Louisiana, so it gives us a lot of optionality. To the extent prices are higher and cash flow's higher, clearly, we could ramp up and grow quicker. But our intent is to be at or near cash flow and we think 20% growth at or near cash flow, organically, is very strong.

Okay. Fair enough. And then just a quick one for me, in Terryville you guys lay out the economic slide $8.7 million well cost. But sounds like you're just kind of starting to implement your own techniques there, and curious if you have a goal of where you'd get that well cost down to with John making the move down from Pittsburgh to Houston? Thanks.

That's a great question. It's hard to peg a number yet. But we've only had – John's only had his reins six weeks, and has already had some great wins. And so I'll just characterize it as saying it's going to be significantly better. I just don't know how to peg that number yet. We just need a few more quarters under our belt to understand where we can really go with that.

Great. Thank you.

We're nearing the end of today's conference. We will go to Mike Scialla of Stifel for our final question. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Yeah. Thanks. Morning, guys. Just wondering on, could you talk a little bit about the potential drilling inventory in just the Upper Red within Terryville, and how the tighter landing interval may have an impact on that?

Yeah, Mike, this is Alan. I think that when we went back – and let me take you back a little bit in time and talk about the acquisition and how we evaluated this thing. So as we went through, we recognized the Upper Red was really the dominant producing interval at that point in time. We recognized the changing target interval – optimizing target interval could have a material impact in terms of productivity per well. And well results and EURs could improve over what we're currently providing for you right now. So with that – and then we also think that also applies to Lower Red and the Pink intervals as well. So the same type of thing is going to happen. So with that, it's going to give us a fairly significant inventory of locations throughout Terryville, from the Upper Red down through the – or the Upper Red, the Lower Red, and then up shallower with the two Pink zones. So don't have a – not going to give you a specific number, but I can tell you that it's going to give us a fairly significant inventory moving forward. Going back through the whole process answering a question earlier, we think we're going to be able to grow productions down there fairly significantly, be able to drive down the gathering and processing rate as well because of the fact (57:36). And I'll be able to do it within cash flow is what our acquisition models show. And so we think it's right in line with what we currently have. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Not to try and pin you down on a specific number, Alan. Just in terms of like, Netherland Sewell had some numbers out with MRD. Are those in the ballpark, or are you talking about something significantly different?

Well, when we did our – to come back to our analysis – when we did our analysis, we didn't look at Netherland Sewell's analysis. We didn't look at MRD's analysis. We did our own analysis. And my answers on this thing when people have asked this, we have what we believe is our analysis going forward. There's a lot of confusion, I think, that's been out there historically between some of the different analyses that are out there. So as we continue to roll through this thing and get our arms around it, we'll provide some more clarity probably toward year-end.

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

Thanks for participating on the call. If you have additional questions, please follow up with the IR team.

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