Good morning. Welcome to the Range Resources Fourth Quarter and Full Year 2015 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 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. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir. Rodney L. Waller - Senior Vice President & Head-Investor Relations: Thank you, operator and good morning and welcome. Range reported results for the fourth quarter and the full quarter for calendar year of 2015 with record production, a continuing decrease in unit costs, significant proved reserve additions, and possibly the lowest drill-bit finding cost for 2015 of $0.37 per Mcfe. The speakers on the call today are Jeff Ventura, our CEO; Roger Manny, Range's CFO; and Ray Walker, our Chief Operating Officer. Range did file our 10-K with the SEC yesterday. It should be available on our website under the Investors tab, 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, unit costs per Mcfe and the reconciliation of reported earnings to adjusted non-GAAP earnings that are discussed on the call today. Now, let me turn it over to Jeff. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you, Rodney. Given the challenging price environment, our capital spending budget for 2016 is projected to be $495…

Thank you, Mr. Ventura. Our first question comes from the line of Jon Wolff with Jefferies. Please proceed with your question.

Hey, guys. Good morning. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Good morning. Ray N. Walker - Chief Operating Officer & Executive Vice President: Good morning.

A few here. You may have been asked this before, but you obviously got a great price for Nora, but can you talk about what that does to your natural decline rate? Alan W. Farquharson - Senior VP-Reservoir Engineering & Economics: Yeah, Jon. This is Alan Farquharson. Our decline rate still stays relatively consistent with what it's been historically. The reason why the Marcellus has been such a dominant producer in terms of total production, if you think about it, last year we made about 1.4 Bcfe a day and Nora was 100 million, just using some round numbers. So the decline rate first full year still is around 19% and then declines. Within five years, you're back under 10% again. So that's pretty consistent with what we've seen over the last year. I think that a lot of people haven't really recognized how shallow the decline is in the Marcellus overall.

A little more granular on that. I mean, it's such a low number, given – without the tight gas sands of the past and without Nora. Would that be a testament to the sort of average age of wells because certainly first year declines are not anywhere near 20%? Alan W. Farquharson - Senior VP-Reservoir Engineering & Economics: Yeah, I think it's a function a little bit of the average age of the wells, but I think it's also – the first year kind of declines fairly steeply in a lot of these shale plays. But then I think most people probably don't look at year two, three, four, and five and then you see how flat some of the declines are. If you look at a lot of the historical data that's out on the PA website, you can see that those wells get fairly flat, relatively flat relatively quickly. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: I think an important point to note is if you look at Range's reserves year-over-year for the last 5, 6, 7, 8, 10 years maybe, our reserve revisions have been positive almost every year and really that speaks to the quality of rock and the wells are continuing to outperform. Again, that's not something that I think happens everywhere, but the fact that we haven't had reserve cuts and in fact we've got positive revisions gives our management team great comfort as well as our banking group. So part of that is – and if the wells are outperforming by definition than the declines are shallower. Ray N. Walker - Chief Operating Officer & Executive Vice President: And also I'll just add one more thing in, Jon. This is Ray. That I think if you look at our type curves that we updated in the presentation, you'll see that last year's production in a couple of those areas seems to be pretty flat and I think people don't realize, most of our wells come online under constrained conditions. So that first year decline that most people think is there is somewhat muted compared to a lot of other places. So I think that contributes to it also.

Just thinking about capital efficiency and the decade-long process of in-fill acreage drill, purchases and building pads which if you could remind me how much they cost? I think last year – one time you're in kind of single well pads and then more recently I think it was four to five or five to six per pad, wells per pad. Can you update us on that and also the cost of a well pad? Ray N. Walker - Chief Operating Officer & Executive Vice President: Sure, Jon. The pad construction phase or building a pad and a road can average anywhere from $400,000 up to $1 million depending on the terrain and the locale and whether it's got wet land streams next to it and all those sort of things that we have to do from erosion and sedimentation protections in Pennsylvania. So on average, $600,000 or so to $700,000 maybe. We have always drilled probably no fewer than three or four wells per pad, and in most cases, we average around five, I would guess. This is the current average. We can do some more research on that and see. But I think it's about five. We have drill pads up to 9 and 10 and 12 wells, but on average, it's about five. We have very few pads that are less than three or four anywhere from history. I mean, we had a few very far step-out pads early on that were one or two or three wells, but that's literally been maybe five, six, seven years ago. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Well, let me just add on to Ray a little bit. But like Ray and Roger were talking about, it really sets us up at this point for strong capital efficiency going forward and the optionality to go back to those pads and drill on those pads where you've got a lot of the costs already. And the team has done a great job. So going forward, there is a really built in capital efficiency, and I think it's a strong statement to say even in this environment. We have a recycle ratio greater than 1 by being able to... Ray N. Walker - Chief Operating Officer & Executive Vice President: Yeah, unhedged.

Yeah. That was the context of the question. I just wanted to get some numbers around it. The other thing on limiting the number of wells per pad, if I recall in the past, talking to you, some of it had to do with the takeaway infrastructure that would be required if you went to seven or eight wells per pad. Obviously, you don't own your own midstream company and maybe that's some of the factor. But it feels like – is there right sizing that – in terms of the amount of takeaway capacity that colors your view of how many wells per pad at least on the initial phase, I know you plan to go back to well those pads later? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: We'll kind of tag team the question. I think if you look at slide 18, that kind of tells the story. We have a huge acreage position and what we think is the core of the ploy. So early on, we're limiting the number of wells per pad to be able to drill more pads, to be able to hold that position. And by the end of this year, we're basically done with that. On slide 18, when you look at the – and at this point, it's really well delineated. We've got basically combined potential in those horizons of about 1.5 million net acres stacked, predominantly down in Southwest PA. So we spread – so, for limited capital, we spread those pads out to hold it, but now going forward, it really sets up a strong efficiency to go back and drill on those particular pads. Ray N. Walker - Chief Operating Officer & Executive Vice President: Right. And Jon, it's been literally a 10-year – 9 or 10 year process of building infrastructure with MarkWest when you talk about the wet system for instance. And a lot of that is – the backbone of that system is finally in place. And I think another concept is when we go back to one of these pads, I don't think we'd be going back and drilling all 18 wells. We would go back and drill two, three, four wells to kind of fill in that room that's now available because of the natural decline of the system and so forth, plus the fact that, like Jeff said, we've been talking about for a couple of years now that we had targeted about 2017 when the HBP kind of factor would be almost gone, and we're literally on the precipice of that. So we can literally, starting in next year's plan, really focus on the highest returns and where there is room in the systems whether it's the dry systems in East Washington or the Allegheny County or in the wet system. We have that much flexibility and that diverse set of assets, like Jeff was referring to.

Last one since my mailbox is being inundated with the question around transport and gathering costs going up, and I assume that has a lot to do with Mariner East 1. I guess, my question is – I guess number one is, I think that's the big reason, but maybe confirm that. And then second, is propane at least getting a better revenue value than natural gas, and is there sort of a positive uplift from processing propane, understanding that these costs are fixed than some costs? Ray N. Walker - Chief Operating Officer & Executive Vice President: Well, I'll start. I mean, yeah. I mean, you're right. The additional costs are mainly from Mariner East starting up. And so we have that cost that goes on that line and the transportation on it. But it results in netback pricing both propane and ethane, that's far better than anything we've got in the past, so it way more than offsets and then Spectra's Uniontown to Gas City is a good example. The transportation cost on that line also gets added, but then when you net-net it all out, we're selling gas for sometimes $1 better than what we're selling it in to, results in $0.40, $0.50, $0.60, sometimes up to $1 better netback price. But I'll turn it over to Chad to talk a little bit more about propane.

Yeah, Jon. This is Chad. We have worked on – since we moved the in-service date of Mariner East, we worked with the (43:09). I think we announced that we had a long-term agreement with (43:13). They have a global presence, and they are helping us and advising us on selling propane into the international markets. So since we announced the arrangement with them, we've locked in arb between mainly Europe and what Mont Belvieu prices were. So with that arb locked in for all of 2016 and part of 2017, we've captured that value that's much better than Mont Belvieu. So it's much better than Mont Belvieu and it's better than gas that we could get on a gas price equivalent basis. Of late, you've watched freight, the Baltic Index on freight costs come way down. This time last year they were about – equivalent of about $0.12 a gallon to $0.14 a gallon. You can currently get a freight rate Baltic Index quote of about $0.035 to $0.04 a gallon. So the freight rates have played into our hand as well. So we're at the end of the day going to be able to get – at Houston plant, we're going to be able to get a Mont Belvieu equivalent to maybe minus $1 or minus $2 which is much better than any of our peers. So we're excited about Mariner East coming fully in service where we can take advantage of loading VLGC ships, lots of volume which will lower our per unit cost of shipping.

That helps. Thanks, guys. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you. Ray N. Walker - Chief Operating Officer & Executive Vice President: Thank you.

Thank you. Our next question comes from the line of Ron Mills with Johnson Rice & Company. Please proceed with your question. Ronald E. Mills - Johnson Rice & Co. LLC: Hey. Good morning. Ray, from a timing standpoint and as you talked about capital efficiency, at what point do you think you'd go back and start to drill again on those pads and be able to leverage the prior expenditures on the pad construction? Ray N. Walker - Chief Operating Officer & Executive Vice President: Well, Ron, it's a good question. We, for the last couple of years, we always seem to have a small percentage of our wellbore going back in an area and doing that. I think this year, there's a pretty small percentage of the wells that are on existing pads. I think really going into next year, and of course, we're just announcing this year's plans, so we've got a lot of work to do to figure out exactly what we're going to do in 2017. But I do foresee us probably starting to make more of a move towards that in 2017. Of course, a lot of it depends on pricing and what all happens this year and I think with the big capital cuts that everybody is going through and the rig counts falling and lots of people choosing not even to drill per se that we're going to see the gas production roll over and we're clearly seeing gas demand increasing. So it's just a matter of time before things start changing and I think we're going to have to get much later in this year before we see how that works out and exactly what our numbers are going to look like for 2017. Ronald E. Mills - Johnson Rice &…

Yeah. This is Chad. We actually started taking our propane in kind in the fourth quarter of 2015. Mariner East was not fully in service. It was not fully refrigerated. So we still were loading on what's called handy ships, handy ships are smaller volumes, they can take about 150,000 barrels. So the per unit transportation cost is a little bit higher which our netbacks were not as good as with Mariner East fully in service, refrigeration is in service and we can load the VLGC ships. But our main focus on marketing the propane once it's fully in service is either take advantage of the arbs between Europe, Asia and Mont Belvieu and/or the local markets. We can sell into the local markets in, for instance, the winter months when propane prices spike if we get a polar vortex. So we have that optionality to be able to find the best price for the propane whatever time of year it is, if that makes sense Ronald E. Mills - Johnson Rice & Co. LLC: With the pricing throughout not flat, but it should have a smoothing impact on the prices through the year for NGLs, correct?

Yes. Ronald E. Mills - Johnson Rice & Co. LLC: Okay, perfect. That's all for me. Thank you.

And we're... Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you.

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed with your question.

Hey, guys. Good morning. Roger, I know we share the same love of the recycle ratio and appreciate you putting that slide on the website. I wanted to ask you kind of on the three variables that you could control in that equation. One on the F&D side of things, you threw a $0.40 number out right now. But you really highlighted that you move to infrastructure, you move to dry gas area, that could potentially come down lower. Curious on activity levels, you've got 37% activity geared to the dry gas areas right now. Can you increase that more going forward given this best economics? And then the second part of it is just on the confluence of the differentials and the transport costs. You guys have shown out to 2017 more downward pressure on the gas differentials. Curious if you – on slide four, you throw your cost on the transport side out to 2016, curious what that could look like going out to 2017? Thanks. Roger S. Manny - Chief Financial Officer & Executive Vice President: Okay, Mike. Yeah, let me comment on the recycle ratio and then I'll turn it over to Chad on the differentials. And you're exactly right, I share your enthusiasm for this ratio. I mean, we went through a period where in the old days F&D costs really mattered. And then we went through this period where everybody had oil and gas coming out of their ears and margins were great and then nobody really cared about it. It was all about margins. And now, I think, it's coming back into vogue and as it should be because, in times like this, positive recycle ratio unhedged, as I mentioned, I think is the key to keeping things afloat. The $0.40 number that…

So part of your question was discussing also future basis differential, and when you look at currently and going into 2016, Dominion South and M2 are still pretty much under pressure. But with some of these new projects, takeaway projects coming on line, the indexes are improving if you look at the forward curves of indexes. (53:17) in Dominion South improved a little bit but not that much, maybe going from $1 to $0.60 or $0.70. But specifically for Range, if you look at slide 15 in our presentation, it talks about our firm transportation takeaway in 2016 and 2017. And though it increases, it's part of the increase in our transportation and gathering when you look the cycle margins. It increases the cost, but also our basis differential improves, both in 2016 midpoint of around $0.42 and then going out into 2017 when some of other projects come into service, it improves even more, midpoint of about $0.28 to $0.30. So that's just helping the margins.

And then the final part of that, probably just a multifaceted question there, is the transport and gathering into 2017, $1.05 in 2016, what's kind of the trend there? Do you expect more upward pressure on that, or could it stay at that level? Roger S. Manny - Chief Financial Officer & Executive Vice President: I think it's going to be – it's going to move around a little bit, Mike, but it's – over time, again, I know we've said that, but as we continue to build out, that's going to plateau, and eventually it will move down as we start to fully maximize the capacity. But again, the big bump is incremental projects that produce incremental margin, incremental revenue. So we're not too upset about the increase that we had in the fourth quarter and that we've announced for the first quarter.

Got it.

The real key on the transportation per unit cost is, as Ray and Roger have talked about, we're going to be putting more and more volumes on, but you're not going to be spending more dollars on gathering and compression. Therefore, your volumes are going to be able to lower that cost just with the volume changes.

Okay. Ray, switch gears, just a quick one on the Oklahoma assets you have for sale. Can you give us the teaser on this? And just I'm curious how much exposure you've got to the STACK and SCOOP? Thanks. Ray N. Walker - Chief Operating Officer & Executive Vice President: We've got BoA marketing it. It's about 28,000 net acres spread across four counties, about 6.5 million a day of production. The acreage is 100% HBP by all legacy vertical wells, about 6.5 million a day of production, about 80% of that is gas. It's right in the heart of the activity where Devon bought Felix's acreage and where Continental is drilling and Newfield is focused. So we will be receiving the bids soon. And we'll be evaluating the valuations and making a decision here probably by the end of March.

Great. Thanks a lot.

Thank you. Ladies and gentlemen, this concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: I'd like to close with the announcement that Rodney Waller will be retiring this May. We pretty much appreciate Rodney's contributions over the years, and we wish Rodney the best in his retirement. Rodney has been a committed shareholder since 1988. He has built a strong team and Laith Sando has been promoted to continue as Vice President of Investor Relations. We have great confidence that Laith will do well in his new position and the team will continue to be responsive to your questions. Thanks for participating on the call. If you have additional questions, please follow up with our IR team.

Thank you. This concludes today's conference. Thank you for your participation. You may now disconnect.