Greetings and welcome to the Range Resources first 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 risk and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's 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 Resource. Thank you, sir. You may begin.

Thank you, operator. Good morning, everyone, and thank you for joining Range’s first quarter earnings call. The speakers on today’s call are Jeffrey Ventura, Chief Executive Officer; Ray Walker, Chief Operating officer; and Roger Manny, our Chief Financial Officer. Hope you’ve had a chance to review the press release and updated investor presentation that we’ve posted on the Web site. We’ll be referencing some of the new slides this morning. We also filed a 10-Q with the SEC yesterday. It’s available on our Web site 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 financial measures. In addition, we posted supplemental tables on our Web site 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, Ray. Since our last call, we continue to make progress on several fronts. On the marketing side, INEOS is now routinely picking up ethane at Marcus Hook and shipping it to Norway. At the same time, we are now loading propane on VLGCs and shipping it to various international markets. The ability to ship ethane and propane out of Marcus Hook is a significant competitive advantage for Range. As an E&P company, we’re now able to connect a large percentage of our NGL production to end markets, the buyers and consumers. As represented in our guidance for 2016, it has a meaningful impact on both NGL production and pricing. Given our transportation contracts for 2017, approximately 70% of our natural gas is projected to be sold in markets outside of the Appalachian Basin, further improving Range’s expected natural gas differentials going forward. By the end of 2017, we expect to increase the amount of natural gas to be sold outside of the Appalachian Basin to about 82% of production. On the asset sale front, we recently closed the sale of our Bradford County acreage in Northeast Pennsylvania. The sale price was approximately $112 million. This was our only non-operative position in the Marcellus. We have also recently signed a purchase and sale agreement for a southern acreage package in the stack play in Oklahoma. We have agreed to sell around 9,200 net acres and approximately 5 million cubic feet equivalent per day of net production from approximately 200 wells in Blaine, Canadian and Kingfisher Counties for about $77 million. We expect to close by the end of May. The remaining northern acreage packages predominantly in Major County, Oklahoma consists of approximately 19,000 net acres and is on trend in north of the existing stack play and is in…

Thanks, Jeff. What I’ll do this morning is cover our production guidance, provide some examples of cost reduction and efficiency improvements, give some color on well performance, and talk about some of the potential opportunities that we see going forward. We continue to remain focused on capital allocation and our production growth is a result of high quality properties being developed by a strong technical team. Production for the first quarter came in at 1.38 Bcf equivalent per day with 33% liquids. And for the second quarter, we’re setting guidance at 1.41 Bcf equivalent per day, with 32% to 35% liquids. Of note, during the second quarter, we expect to fully replace all the production sold from our three sales and our annual guidance moves to the high-end of our previous guidance and is now expected to be 1.41 to 1.42 Bcf equivalent per day. We believe this year will look very similar to previous years with sequential quarterly growth and our exit rate will be higher than it was at the end of 2015, setting us up well for 2017. For the first quarter, we continued to drive down our overall unit cost, resulting in a reduction of 10% from the prior year's quarter. Basically, all of the categories beat guidance. One particular item that I would like to call your attention to is the LOE. Our operating teams continue to operate more efficiently. And when coupled with recent asset sales, our LOE per mcfe is 37% lower than a year ago and 14% lower than the prior quarter. Capital efficiency continues to improve. I’ll go through just a few examples from our operations in Southwest Pennsylvania. On the completions front, we completed 1,324 stages with 2.25 crews during the quarter, setting another record. Compared to the first quarter…

Thanks, Ray. There were many successes in the first quarter of 2016 as Range continued to effectively position the company for the current economic environment and a future with higher takeaway capacity and better pricing. Starting with the balance sheet this time, we ended the quarter with less debt than we entered and our capital spending plans are right on track to produce prudent growth in production and reserves with improving capital efficiency. A major highlight of the quarter was the unanimous reaffirmation of our annually-determined $3 billion bank credit facility borrowing base. Beyond the committed liquidity it provides, looking behind the numbers at the approval process reveals three significant positive read-throughs. First, the reaffirmation excluded the collateral value associated with the December 2015 Nora sale and the two more recent asset sales, which in aggregate exceeded $1 billion in sale proceeds in the unique portfolio of value-added marketing arrangements we have for our natural gas, NGLs and condensate, which will improve future pricing. Our recycle ratio, based on our year-end 2015 reserve report F&D cost, projected 2016 unit cost structure projected 2016 basis to NYMEX and current unhedged strip price for 2017 is approaching two times, ensuring that we can continue to grow our reserves and production within unhedged future cash flow. As I mentioned on last quarter's call, we believe, an underappreciated element, that balance sheet strength and preservation is having an unhedged recycle ratio above one times which allows for both growth and debt reduction at the same time over time. Our first quarter ending debt-to-EBITDAX ratio for the past three years has been 3 times, 2.8 times, and 2.9 times respectively. The ratio at the end of this year's first quarter is a very manageable 3.3 times. As a reminder, Range has no debt-to-EBITDAX covenant, no…

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

Thank you, Mr. Ventura. [Operator Instructions] Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Please go ahead.

Thanks. Good morning, everyone. Good morning, Jeff.

Good morning.

Jeff, first of all, congratulations on another very strong operating quarter given the circumstances. But, I guess, the question that seems to be getting asked to a lot of your oily peers is, is there a level when you would consider putting rigs back to work? Now, I realize $2 gas price may be a little premature or certainly irrelevant in this market. But just conceptually, given the efficiencies that you have baked into the system, given the continued improvement you delivered for the last several years, what is your philosophy in terms of how you see Range’s longer-term targets evolving, assuming that gas prices do improve? And I’m thinking back to when you used to talk about 20-plus growth as an annual run rate in the longer-term.

That’s great question. Let me talk about it in a very conceptual way. Again, I think we’re in a great position. We’re in the highest quality gas play that’s there with economics, I think, that really rival any play. It’s a stack pay area. By the end of this year, it’s predominantly HBP, so we’ve got a lot of optionality not only in drilling Marcellus, Utica, or Upper Devonian, but drilling wet or dry. We’ve got really low maintenance CapEx, which I think is important. And I think is – if it isn’t best-in-class, it’s clearly right up there. Coupled with really good marketing agreements. Now, there are a lot – our newest piece that’s in place, Mariner East. So the ability to move ethane, propane or natural gas really to multiple markets around the US or even internationally, the ability to go back on existing pads, those are all key things. So I think what you’ll see is too is we’re in great shape in a low-price environment. We believe that a lot of good fundamentals are setting up for natural gas to improve. We think this will be the first year natural gas supply rolls since 2005 or something back like that, coupled with a time where demand is coming up. So in a lower – for a longer scenario, we are well-positioned. In a higher price scenario, we have a lot of optionality. Ray has talked about it and can continue to talk about. I think when you look at our fracking efficiency, it’s probably best-in-class or right up there, our drilling efficiency and wells. So we have the ability to ramp when need be. But we’re going to be very returns-focused. We’ll be sensitive to balance sheet and those types of things. So we have – we have a lot of optionality to push the throttle forward or to pull it back, which is, I think, the position that we want to be in. So that’s kind of a long-winded answer, but I think philosophically we’ll think about the returns we’re getting. We’ll think about the balance sheet and all those types of things. But we have a lot of optionality with what we have. The team continues to get better, better and better as evidenced by the capital efficiency and we have tried to slice and dice that in multiple ways, everything from a high-level graph that shows our capital efficiency to some of the specifics. And, again, feel free to ask Ray about some of those. I think when you look at them versus peers, they are impressive numbers. So that’s kind of philosophically how we look at it.

I guess what I’m kind of struggling with this if you assume any kind of modest recovery in gas prices, you could pretty much make your growth rate whatever you wanted it to be. So I’m just trying to think how you would trend limits around that, whether it would be balance sheet or some kind of EBITDA coverage ratio or…?

Yeah, yeah. Clearly, balance sheet is important. Spending typically is going to be – I think, philosophically, is going to be at or near cash flow – or at on your cash flow. But I’ll basically leave it at that. Roger, do you want to add on to that a little bit or…?

I think, Doug, it’s going to be game time decision when we move forward and we’re just going to read the market and we’re going to look at all the dials and adjust the throttle accordingly. I just don’t think it makes any sense to try to lock into a number right now. It’s too dynamic.

Absolutely, I understand. My other question is really just a little bit more – it’s less about the operations and more about the disposal program. You held on to the stack, Jeff. I’m just wondering what we should read into that. Are you looking for a better market? Or are you thinking – if that’s something you might want to put your own capital to work in at some point?

Let me clarify that one. We marketed that in two pieces. The southern package was actually in the stack play. It was about roughly 9,000 acres of – scattered across three counties, kind of small broken up pieces, but in the play, collectively producing about 5 million per day equivalent net from 200 wells – 200 all legacy, vertical wells. You can do the math there. So the price that we got for that, we thought, was a very strong price for that kind of position, particularly in today’s market. When you looked at the northern piece, which is bigger, and about 19,000 net acres, it’s mainly in Major County – predominantly in Major County, which is north of the stack play. But the play is clearly moving in that direction and there’s rigs coming right up to us. And it’s also in the emerging Osage plays and there is other plays. So we actually have eight rigs drilling in and around us. It’s all HBP. So our thoughts are to just wait, watch some of the drilling results that we expect will be good and just sell into a better price. So we have – because it’s HBP, we have the optionality of time. So I think you’ll see us sell that and market it in due time. There’s a lot of drilling activity. You can take a map of our acreage. It was up on our Web site at one time or the IR team will give it you. You can look at the active rigs, I’m sure, if you subscribe to those services. There’s a lot of activity around us. The remaining stuff we have in the Panhandle and up in the northern Oklahoma, I think you’ll just see us sell us with time, but we’ll do it at an opportune time. It’s similar to the Nora sale. We didn’t just – Nora, we had to find the right buyer at the right time. We were very pleased with the sale. Hopefully, it’s a win-win for both sides. But it’s finding that buyer that really likes the asset. Bradford County was the same thing. I know people that follow us, we had that for sale for a long time. We’re very disciplined and we finally found the buyer that paid us what we thought was a price. I think if you look at both of those cases, the price we got was about double what most of the people thought Nora or Bradford County was worth. So I think the remaining stuff in Oklahoma, particularly that northern part of the acreage in Major County, it’s just picking the right time and the right buyer. But you’ll see us sell that with time.

Great stuff, Jeff. Yeah, we’re watching you very closely, as you say. I’ll let someone else jump on. Thanks a lot.

Thank you, Doug.

Thanks.

Thank you. Our next question comes from the line of Neal Dingmann from SunTrust Robinson Humphrey. Please go ahead.

Morning, guys. I certainly would echo Doug’s comments. You were great operationally. Jeff, one question for you, and then more to Ray on the efficiencies. Just on that last question, Jeff, additional non-core sales, just kind of wondering what else you’re seeing out there besides, obviously, you had two strong sales here recently. Are there other things you could tee up here shortly?

Clearly, I think the Major County package, it’s probably marketable. I hate to always put time frames on them. But I think, later this year, or at the optimum time, we would definitely consider that stuff. In the Texas Panhandle, we have a nice position that. It’s non-core to us. There’s other people that really like that area. Mississippi, and again, and you can even – we carved off Bradford County, so it was a little slice of the Marcellus that wasn’t key to us that was important for somebody else. You can envision things like that with time.

Okay. And then, maybe for Ray, I was definitely intrigued by our comment that 50% plus of you wells, as you mentioned, next year could be on older pads. And so, I’m looking at that, plus, obviously, just doing the bigger pads, the six to nine-well pads. Ray, based on that and those type of efficiencies, what type of cost savings are potential? It looks to me like it could be quite large.

It’s a great question. It’s more of a continual process. If you look at page eight in our presentation, we show what we’ve been able to do literally and what I think that matters at the bottom line is the total cost per lateral foot. And you look at that over the years and you’ve seen really good improvement. And even the cross years where service costs were actually going up, we were making significant improvements. A lot of that’s driven by drilling longer laterals. It’s just the fact that our teams and our service crews are getting more and more experienced, all of those things factoring in, are allowing us to keep doing what we’re doing. And I think that we’re going to see probably half of our wells – could be less, could be more – we’re really, really early in the planning cycle at this point. But some of the things I talked about in my prepared remarks – and when you couple the savings or the fact that you don’t have to build pads and roads and production facilities, other things that we don’t talk a lot about, or things like survey, land, title curative, we’ve got water infrastructure and depending on where that pad is in relation to the current water infrastructure we have in place, all of those things you could save couple of hundred thousand dollars a well or you could save up to $850,000 a well depending on the particular situation. And I think those kind of savings are real. I think it’s taken us lots of years to develop a very large core asset area. We’ve got a great low base decline rate which allows us to build very efficiently with the capital that we allocate. We’ve got some – clearly some really high prolific performing areas, like I went through them in my remarks. Couple of examples there that we can focus on. We’ve got new infrastructure that’s always continually still being built, like some of the new dry gas stuff I talked about in my remarks. So I think it’s just all – and you roll all that together, the fact that we’ve got a great transportation portfolio, we’ve got diverse outlets for operational aspects and as far as pricing aspects, a lot of these things have taken years to develop. All of our HBP concerns are covered this year. And so, we’ve got a great future going forward. And I think we can just continue that capital efficiency. The service contractors can continue to give us great pricing because of the high utilization rates. We don’t think anyone else in the Basin is operating at the number of fracks per day that we are or anywhere close. So I think there is a lot of things out there like that that just give us a pretty unique advantage when you compare us to all of peers.

Great, great. And then one last one, if I could. I love that slide 15, your gas and plays. I know you and Bill were probably the first ever to put that out there. And I’m just wondering, number one, is that continuing to grow? Obviously, you look where that red area was and, to me, you guys have been dead right here now for the last couple of years on that. Two questions, I guess, around that. One, do you see that expanding at all or are you pretty content there? And then secondly, when you do some of these dry Utica gas wells there, in order to keep the cost down, what things can you do? I guess because of the pressure, do you still have to use the ceramic versus the sand? I’m just wondering what things you can do in that area to keep the cost down on those dry Utica wells?

All right. Two great questions. I think the gas and plays math, we’ve had for a long time internally. And then, of course, we made them public, I guess, two or three years back. And they’re actually holding very true. I think, as we’ve seen, more and more development occur in the Utica and in Upper Devonian and, of course, in the Marcellus. I think they’ve held really true. I think it’s going to be like – most plays, historically, have been where the true core sweet spots tend to shrink and so forth. I think that’s a big reason behind our low base decline rate, is I think we have better hydrocarbons – better hydrocarbon content, I should say, better perm, better porosity, better pressures. So we get better desorption of gas in the long run, a lot of those things help us. But I think they’re going to hold pretty true. Clearly, the Utica is really early, especially on the Pennsylvania side. But we’re pretty pleased about that. Going forward on the Utica, we think when we get ready to do the next well and we’re not sure when exactly that’s going to be yet, but we can do, based on what we know today, a 6,500 foot lateral for around $12 million – probably less now. An 8,000 foot lateral or so, we can probably do for about $14 million or less. We think that’s probably an industry-leading cost already. We’re a little bit shallower than some of the other wells. So there’s a little bit less cost there. We, in our last well, completed it with – I think it was 5,800 feet with 38 stages and we were 500,000 pounds per stage and it was 50/50 100 mesh and 40/70 premium white sand. So we…

Very helpful, guys. Thanks so much.

Thank you.

Thank you. Our next question comes from the line of David Kistler of Simmons & Company. Please go ahead.

Good morning, guys. And great work. This goes back to kind of the existing pads and the cost savings that you talked about there. Obviously, the low-hanging fruit is the fixed cost component, the pads that are there, the tanks, the roads, et cetera. But can you give us a little bit more breakdown in terms of how you guys think about it in terms of what it does to the actual operating cost metrics and the gathering side of the component and how that will flow through and whether that's truly captured in this $250,000 to $850,000 well savings you talk about?

Yeah. Dave, this is Ray. It’s a great question. Again, the savings – the $200,000 to $500,000, let’s say, or $600,000, whatever it might be in a particular case, that’s going to be the dirt work, things like building the pad and the road, then you’ve got the actual production facilities which, as you know, the separators, the production tanks, the heater treaters, all those different things. They’re going to be different in the super rich versus the wet versus the dry area. They’re all different. I think people tend to group this together and say, it’s going to be the same all the way across and they forget that, number one, we have a really large position and, number two, it’s really diverse. So we’ve got lots of different designs of facilities that we deal with. But it’s going to be all of the meter taps, things like that. Then you’ve got things like damages that you pay the landowners, survey cost, title curative, you’ve got a lot of different things like that that we don’t talk a whole lot about, which are really significant. You’ve got water infrastructure. If it’s a pad that’s right near an impoundment or right on a pipeline network, of course, the water cost could vary by several hundred thousand dollars on a pad. And some of the new things that we’re doing lately, today, we’re saving, on average, probably $300,000, maybe $350,000 per pad on water cost. It’s that significant when you’re drilling a new four-well pad. It’s really significant if we just go back and add one or two wells on a pad. So I think those things are – all the capital costs that roll in there. If you think about going back on to an existing pad and there is…

I appreciate that color. That’s fantastic. Maybe kind of building off on the last point there, when you guys start selecting which pads to go back to, can you talk a little bit about how much maybe closest proximity to highest price markets factors in? You already indicated a little bit in terms of how important it is to be closer to various infrastructure just in terms of being able to get that gas or NGLs to market. But how much of that factors in also to the decision of how you select the pads and the timing of when you’ll be going back to various areas, whether it be super rich, wet, dry, et cetera.

That’s a great question, Dave. And it’s really all of that. Plus, I would add in there, it’s not always going to be going back on existing pads because we have some – in some of the stuff I talked about in my prepared remarks, some of these wells that – I talked about the recent performance and then some of the existing wells that we’ve done and following up, like that example of the ten different wells from several different pads. When you look at that, the economics on that stuff – even if you build a new pad is probably better than going back on the existing pads in today’s world in the wet and super rich area. So we’ve got that flexibility to go both ways. And it really comes down to what gives us the best overall project return for our capital in a year’s time. Where are we going to be able to – if you put a dollar in, where are we going to get the most dollars out? And it’s really that simple. But we have to factor in all those things you talked about, whether it’s markets, proximity to infrastructure, timing of sales that we’ve done with customers, all of those different things factor into that.

I appreciate the added color and great to see the scale and scope is now really starting to kick in on the asset base.

Thanks, Dave.

Thank you. Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Please go ahead.

Thank you. And good morning, folks.

Good morning.

Good morning.

Couple of questions quickly, if I may, on cash margins. Regarding your guidance on differentials in NGL pricing, what potential do you see for that to change either the back part of this year or periods beyond that? Can we see narrower differentials on more gas leaving the basin and better NGL pricing on barrels being shipped than what’s guided?

I will maybe tag-team that. But I think if you look on slide 14, it shows projected average differentials in 2016 versus 2017. So we were expecting those differentials for the year to average $0.40 to $.45 less from NYMEX. Into 2017, the expectation is that could improve to $0.25 to $0.35. We expect significantly better NGL pricing this year as a result of new contracts and movement – Mariner East starting up, plus some of the early things where we have kind of that optionality to either export or move in the US markets. Again, being a competitive advantage being the only producer who has capacity on Mariner East. But when you look at slide 14, coupled with some of the slides in there about the NGLs, we think that we’ll see significant improvement.

Okay. And then a follow-up to that, just confirming that your guidance on transportation costs capture the increase in production being priced outside of the Appalachian Basin, just inquiring, again, just to assess the risk to cash margins here going forward.

This is Ray. I’ll answer that. All of those projections that we put in there going forward are based on the current deals and transportation deals like Spectra's Uniontown to Gas City, cost some money to send the gas over there. But we, net-net, end up with a much better revenue because we got a much better realized price for our gas. Same thing on the NGLs. We’re now transporting 75% of our barrel, ethane and propane, out of Appalachia. The VLGCs on the propane is saving us a nickel a gallon. On a $0.50 a gallon product, that’s a big deal. We’re hedging international spreads on probably a third of our second half of 2016 production and that’s looking really good. Shipping rates have come down to $0.04. They could go lower. We’re hearing lots of good things about the propane market and we’re hearing lots of good buzz about the ethane market. So we’re pretty encouraged going forward. Can’t peg down exactly when it happens, but I think, again, with us focusing on our low-cost structure, multiple outlets not being dependent upon any one particular project, we’re set up really well going forward.

Got it, thank you. And many thanks for taking my questions. Have a great day.

Thank you.

Thank you.

Thank you. Ladies and gentlemen, we have now reached the end of the time limit for our Q&A session. And this will conclude our question-and-answer session. I would now like to turn the call back over to Mr. Ventura for his concluding remarks.

Thank you very much for participating on our call. If you have additional questions, please follow up with our IR team.

Thank you, ladies and gentlemen. This does conclude our teleconference for today. You may now disconnect your lines at this time. Thank you for your participation. And have a wonderful day.