Welcome to the Range Resources First Quarter 2019 Earnings Conference Call. [Operator Instructions]. 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. [Operator Instructions]. 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 first quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Dennis Degner, SVP of Operations; and Mark Scucchi, 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 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. Please note 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. For additional information, we've posted supplemental tables on our website to assist in the calculation of EBITDAX, cash margins and other non-GAAP measures. With that, let me turn the call over to Jeff.

Thanks, Laith, and thanks to everyone for joining us on this morning's call. Range is off to a great start in 2019 delivering on the operational and financial objectives to drive our 5-year outlook. In the first quarter, Range generated $53 million of free cash flow and reduce debt by $48 million. We achieved this result through a commitment to capital discipline and a focus on driving higher margins through prudent cost management. This strong start to 2019 builds upon 2018 results is Range's transition to generating free cash flow in the second half of last year and completed our 2018 drilling program for $31 million less than our original budget. This compares favorably to our industry peers as the majority of E&Ps outspent their original capital budgets in 2018. Range's commitment to capital discipline is unwavering, so we reiterate, Range will not outspend our $756 million capital budget for 2019. I also want to reiterate Range's commitment to generating free cash flow if strip pricing improves over the course of the 5-year outlook, we will not increase growth but will instead look to generate additional free cash flow and reduce debt faster, which could position us to return cash to shareholders sooner in the form of buybacks and/or increased dividends. Speaking of the balance sheet, our commitment to organic free cash flow and asset sales have strengthened our financial position considerably and allowed us to reduce debt by $419 million over the past 3 quarters, a reduction that represents approximately 10% of total debt. We intend to build on this momentum through the remainder of 2019 and beyond, translating our high-quality asset base into being full free cash flow generation, while further accelerating our financial targets through asset sales. We believe this will narrow the disconnect we see between…

Thank you, Jeff. Our operating teams are off to a strong start for the year with first quarter production on track and capital spending projected at/or below our 2019 plan. First capital spend came in at $214 million or approximately 30% of our 2019 budget. Production for the quarter came in at 2.256 Bcf equivalent per day as a result of strong well results and incremental [indiscernible] quarter. As we discussed on the prior call, our capital spending program is front-end loaded for the year. As we look forward and similar to past years, we expect our second and third quarter capital spending to each be approximately 25% of the annual budget this year. First, let's talk about the well results. Similar to prior quarters, Q1 generated some exceptional well performance, which played a key role in exceeding guidance. One example is in our Appalachia dry gas acreage where we turned to sales 14 wells on two different pads. With average IP's exceeding 30 million cubic feet per day from an average lateral length of over 13,000 feet. Both pads have produced at/or above 100 million cubic feet per day for 60 days and continue to produce at this level as of this morning. On the other side of our acreage position in the last week of the quarter, we turned to sales three wells in the heart of our super-rich acreage. The average initial production from these wells was over 20 million cubic feet equivalent per day from an average lateral length of just under 7,000 feet. Despite the shorter lateral lengths on this pad, the first 3 wells produced peak condensate production that exceeded 3,000 barrels per day, solidly pointing to the quality of the acreage and results from the team's technical work. Flow back operations in this…

Thank you, Dennis. During the first quarter of 2019, Range continues to execute on a free cash flow generating plan through efficient operations, diligent capital deployment and stringent cost management. From capital to production, revenues to expenses, Range met or beat guidance and has made early progress on the 2019 business plan. On the back of solid operational performance, Range generated cash flow from operations of $261 million compared to capital spending of $214 million resulting in free cash flow of $53 million before dividends and corresponding debt reduction of $48 million. As discussed on the last earnings call, we made the transition to free cash flow mid-year 2018. We've continued that trend and expect to generate meaningful free cash flow for the full year 2019. Focusing on the Range's cost structure for a minute, I'd like to discuss trends and specific components of our unit costs. Our focus on expanding margins includes efforts to consistently realize competitive pricing for our production and to strategically manage costs such that our margins maximize full cycle returns over time. Starting with the largest cost line item, gathering, processing and transport expense was $1.49 per Mcfe in the first quarter. This cost consists of in-field gathering, processing plant expenses and long-haul transport for natural gas and natural gas liquids. Long-haul transport is largely a fixed cost with all of our contracted gas capacity online. Infield gathering has both fixed and variable elements. Much of the gathering system is fully utilized and as cost recovery hurdles are met, the fixed-rate component will decline over time. On the processing side, this is predominately structured as a percent of proceeds from NGL sales and will vary with our pre-hedge NGL realizations. For context, per Mcfe, gathering represents roughly $0.50, transport roughly $0.50 and processing around $0.45.…

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

[Operator Instructions]. The first question comes from the line of Marshall Carver with Heikkinen Energy Advisors.

On the year-end call, you discussed spending approximately 35% of full year CapEx budget in 1Q, but spending came in below that. Was that due to well timing or well costs trending below your forecast? Do you have any color on that why the 1Q spend came in lower?

Marshall, this is Dennis. I'll start of by saying we tried to highlight this morning a couple of key themes on what helped us basically have the capital spend results that we did in the first quarter and a big portion of it clearly is our operational efficiencies. The drilling team continues to really do a great job of advancing the ball on our ability to drill long laterals, and we see that translate into a significant reduction in our drilling cost per foot. The other part is as we saw some efficiency gains this quarter versus last year through our fracturing operations, 20% is a pretty strong move much to our operating team, that helped us harvest some capital savings as well. And then thirdly, the waterside. I mean, it's an area that we continue to see good cooperation between other operators on top of the 100% recycling effort that we have and it translates into significant savings, as you look across the quarters and the balance of the year could translate into more savings on what we're seeing today. So pretty encouraged by that. The 1 pad that we had at the end of the quarter that we referenced in the superrich that we turned in line the 3 wells. There are some wells that moved into the first weeks of Q2, but the majority of those dollars are already spent. So we're going to get the advantage of seeing those volumes show up in Q2, which we're encouraged to see, but there will be a few capital dollars that also show up in Q2.

Our next question comes from the line of Ron Mills with Johnson Rice.

Dennis, you referenced NGL prices and I know relative, given the move up in WTI, it looks like you brought down the low end of the range, but your comments are pretty telling that even when using the strip, the absolute prices are higher than -- are actually looking for trend higher. Any additional color, whether it is about strip or your thoughts on NGL markets as we look through the rest of the year, particularly fourth quarter when the seasonality starts to benefit NGLs even more?

Ron, thank for the question. This is Alan Engberg, I'm the Vice President of our Liquids Marketing team. So I'll see if I can give you some color around liquids. Absolute prices are actually similar to what we guided back in February, there are up for the quarter actually, roughly about $3 per barrel. Now as you know and as you pointed out, crude is up quite a bit more. Crude is up about $15 a barrel for the quarter. Typically, NGLs will always lag crude on the way up and on the way down. However, this quarter there are a couple of one-off events that caused it lag more than usual. So if I start with LPG or starting with propane and butane. Exports, in particular, were one of the big drivers. They were negatively impacted by an unusual amount of fog this year along with Houston Ship Channel. Added to that, there was a big fire at ITC's tank farm that caused contamination of the water way and that further slowed down all traffic on the Houston Ship Channel. And by our estimates, there was approximately 20,000 barrels per day that were impacted over a 45-day period. So 9 million barrels that didn't ship. So that was just a big kind of change to the market that the market wasn't expecting. And note that the rest of the world has really come to depend on U.S. exports, and those delays actually caused a spike in overseas prices, both in Europe and in Asia, that have resulted in -- right know, what we're seeing is the highest LPG arms in roughly 4 years. Going forward, we expect things improve. This was a one-off event, it's over with. The ship channel is pretty much cleared. But on top of that,…

Great. And then one quick one. In terms of completion timing, is there any seasonality in terms of driving so many of the completions being weighted to the dry gas area in the first quarter? Or is it just a function of just moving through your acreage position given the shift in gas in superrich over the remainder of the year?

Yes, Ron. The planning team looks not only at the next 12 months but they'll be looking at the next couple of years. And based upon our type curves and our internal production forecast, we'll be looking at where we have available capacity in our infrastructure and gathering system. The goal will be to maximize utilization of that. So when we see a change in well mix, most of the time, it's going to be tied directly to those drivers. And I think an example of that I'd point to would be toward the end of last year, as we brought on some compression in the northern part of Washington County to support Harmon Creek 1. You saw us then of course through Q4 bringing on several wet gas wells that was then going to utilize that infrastructure that then ties to our long haul takeaway at Rover. So you'll see some fluctuations at time, but it tends to be tied to the infrastructure at how we can best utilize it and keep costs low.

Your next question comes from the line of Rehan Rashid with B. Riley FBR.

Two quick questions. One, the 20% improvement in frac efficiency I think that was mentioned earlier, kind of what changed and kind of how does that drive CapEx per well? If I could get some color on that, that's one? And two, maybe a little bit more color around kind of the divestiture timeline and any particular area that's focus in terms of divesting?

Thanks for joining us on the call this morning. I'll start with the frac efficiencies and hand over to Mark. On the frac efficiencies, we had exactly quantified how all that savings will be translated into our cost per foot as of this morning, but we know that as you look between winter and I'll just say, non-winter operations, they're substantial savings and mainly because of some of the supporting hardware that goes along with our operations during the winter, whether it's supporting equipment, et cetera. When you look at our cost of completing and drilling wells, what we see is that over the balance of time, it translates into reduced cost per foot for us. So when you look a year ago, efficiencies were starting to kind of stabilize at that point. This year, we're seeing through the balance of continuous operations with some of our crews and also increase in our knowledge base on location, we're seeing that performance translate into it really improved performance on location. So really like what we see and expect that this should continue throughout the balance of the year. Now, with some seasonal differences, you might see little bit of a fluctuation, but the crews have performed extremely well, pointing back to our service partner relationships.

This is Mark. On the divestiture front, as we've talked about before, we have a number of processes underway. And again, there are in various stages from negotiations, there's the data rooms to diligence with a variety of efforts underway. We're not good to pin down the timing, but what I can point to is a few facts that hopefully gives us some comfort and some guidance into what we're striving to achieve. So obviously, we were successful last year in closing on the royalty sale and closing October of last year. We will consider royalties again, we've mentioned northeast PA, we mentioned noncore acreage as potential candidates, all those dialogues are ongoing. Another read on the sense of urgency, not just kind of our alignment of interest but the importance of the factor as well as the timing is the addition of an absolute debt-reduction target in the management performance measurements and incentive program as you can see in the proxy. So there are specific targets there for us to strive to achieve at the high end to maximize that metric, that would be a $700 million reduction in debt for 2019. So while we're not going to give specific guidance on timing or dollar amounts of specific transactions, those are in broad strokes how we're thinking about it and what we're striving to achieve.

Okay. Just maybe a different way to ask the same question on the divestiture thought process. Your cost of debt is so much more lower than implied by your cost directly, but when you're thinking of kind of acceptable pricing, what -- would you expect to be more closer to your cost of debt as you kind of divest these assets and the cash flow limits? Or kind of how much deeper would you have to go away from your cost of debt and closer to cost of equity, think about kind of what multiples you would get on your cash flows or anything else associated with it. Does that question makes sense? I'm not sure if I asked you properly.

Sure. I think I understand where you're headed. So the answer would depend on what type of asset you're talking about. For example, some of the acreage is nonproducing so there is no cash flow. So we're talking about a portion of our asset base or inventory does not reflect it clearly and no value in our equity. So that type of valuation metric might not be the most applicable. As it relates to others, you can look at that asset value, full-blown just kind of cash flow valuation and of course, we will look at cash flow in multiples as well. So based on the markets and the interested investors in each of these or acquirers in each of these packages, I would say that these are all we fully expect to be deleveraging type transactions and very reasonable relative to our corporate cost of capital.

Your next question comes from the line of Brian Singer with Goldman Sachs.

You mentioned that your ability to continue to push out lateral lengths with some of the 18,000 feet lateral test, can you remind us year base expectations for how you see well cost per foot, and EURs per foot evolving? And then how long do you think you can push out those laterals until you would either see sufficient operational risk or acreage limitations?

Brian, at this point, we're really confident in the 18,000-foot lateral length that we've been able to drill. I think on the prior call, we referenced that we certainly had a substantial number of laterals that were in excess of 15,000 feet. When you look at -- and we've been able to do this across as we think about our acreage position, both in the core of Washington County where we had historical wells, but we've also been able to do it in areas where maybe we have a cleaner sheet of paper in fewer wells that we're drilling around. So by having a blocky acreage position, the way we do and it being continuous, it really affords us an opportunity, coupled with the gathering system to really -- to maximize that lateral length opportunity. We've typically been a incrementing type operating team. So rarely will you see us go from 5,000 feet to say 20,000 feet in any kind of operation because we understand that we want to manage the risk. And part of being us -- part of us being successful in an unconventional resource play is being repeatable. So getting to the 18,000 feet point that we've gotten today, we really like the results we're seeing. As we look back on the performance of these wells, I'll shift there for a quick second. The wells that we reported toward the end of last year that we drilled. One, it was at 17,800, and the other one as at 18,100, both of those wells are at/or above the type curve, super rich type curve still today. We looked at those results just over the last few days. So we really like what we see on a normalized basis out of the wells. The drilling team continues to push down cost per foot. We've seen, as we've mentioned earlier, as much as a 30% increase. So we really like the direction we're headed. Average drilling length this year, I believe we reported was going to be about 13,000 feet for the program. But when you look at a lot of our references, it's not uncommon again for us to point to 10,000 feet, we feel like that's a good spot as well, but we will have those cases like a few of the super-rich wells we've pointed out that IP'ed at 7,000 feet, so we will have some filling space. But our goal will always be to maximize on the lateral length because we see that is the most capital-efficient approach.

Great. And then to follow up on the divestiture question. Given that this has been an area of focus for some time, can you just broadly discuss how the market environment and marketing interest in Appalachia upstream assets either directly or via royalty compares today relative to 12 to 18 months ago?

Sure. So I'd say, depending on area, the evolution of investor interest and the bid-ask spread has evolved. So for example, in North East Pennsylvania with Atlantic Sunrise coming online, seeing actual sales curve, basis tightening, not just in the forward curves but in the spot market and the actual physical transactions, that gives potential buyers greater confidence in the economics that they're forecasting. So that I would say is an improvement. The variety of interested parties and types of investors remains pretty diverse and strong, there are multiple potential parties in each data room. In Southwest Pennsylvania, I would say that those discussions continue to evolve. Just as an example, after we announced last fall successful Royalty sale, we actually received several inbound phone calls of party saying, "Hey, I wish we had known that, that something that you would consider." So in general, I would say that the A&D market is alive and functioning.

Your next question comes from the line of Jane Trotsenko with Stifel.

In the press release, you mentioned that Range is actually engaged in developing in-basin demand to support the use of natural gas in local markets. Could you please expand a little bit on that?

One of the things that we see, as you can imagine, with the kind of, let's just say, resource certainty that you have in a place like Southwest PA, you're now starting to see more and more discussions around industry development. An easy example to point to would be that with utilized demand. An easy example to point to would be the Shell cracker as an example. We're seeing more and more inquiries now come in for industry development that could be right there on top of our acreage footprint or at least in a very, very close proximity that would allow for us to have some in-basin liquidity as we move forward. Whether that's power generation again or other industries that have a strong interest in moving to the region. We are going to continue to look at those opportunities and make sure that they have a good thorough scrubbing and how they can potentially fit with reducing our cost and be a part of our portfolio going forward.

And my second one is on Northeast Pennsylvania, I'm curious, which pricing point that gas is priced at?

Much of our gas sold out of Northeast Pennsylvania is priced like Leidy.

Leidy. Okay. Got it. And maybe the last question is on Terryville. Maybe you can update your current thoughts, update us on your current thoughts on Terryville, how we should be thinking about activity levels going forward, and if you are marketing this asset as well?

Yes. On-the-go forward, I'll try to take a step back and see. From a Terryville activity standpoint, in the beginning of the year, we've kind of laid the groundwork that it's a area where we're going to spend around 10% of the capital this year with the 90% going to Appalachia. We have some technical thoughts that we're continuing to explore throughout the year and continuing to test. We've got a drilling rig that's been operating there for the past few months and we'll most likely start to wrap up sometime mid-year, pending our results we see over the months ahead. The asset really has to be at the place where it competes on a risk-adjusted basis, and we've got to find repeatability in the results that we see there. As you would imagine, as we look over the balance of 2018 and '19, there are things that we really like and are still excited about from the asset standpoint. But it still has to compete with the Marcellus, and that's what we're trying to work through here in the months ahead.

But just to clarify, you are not marketing those assets as of right now, right?

This is Mark, no. It is not being actively marketed right now but to Dennis' point, you can see the strengthening capital allocation, the approach, the science that's being done there and just assuming out as we evaluate the inventory and think about it -- and think about the purpose of the almost 10% of the capital budget allocated to that property this year, it was around managing that client profit and managing the cash flow from that asset. So just in terms of how we manage the portfolio overall, we'll continue to optimize and do everything we can to maximize the value.

Your next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt.

I was hoping you could reconcile the debt-reduction target with the leverage targets for 2019 and I think you mentioned earlier that $700 million was your top-level target for debt reduction, which I believe implies about $600 million of asset sale proceeds given your organic free cash flow expectations for the year. But on the leverage side of the proxy, it looks like you have 2.5x as your top-level target and my math would imply over $1 billion of assets of proceeds to kind of hit that without assuming any EBITDA loss. So can you just reconcile the difference between the two or provide some context of that how we should think about those 2 metrics?

So the two are conceptually linked, of course, in producing absolute debt but they're not mathematically hardwired because the leverage ratio can change based on commodity prices and other outside factors frankly beyond our control. We will hedge at over 80% on the cash side this year, so that certainly helps add certainty to the trajectory. But the idea there is we evaluate credit holistically. The debt-to-EBITDA ratio was certainly one measure of improving and strengthening the balance sheet. But just an example of why it's important to look at it from an absolute debt perspective as well, you could improve the leverage ratio as debt-to-EBITDA by growing faster and having no absolute debt reduction. So the concept behind pairing those 2 is to demonstrate the fact that we are talking about debt reduction in the absolute as well as improving an entire host of credit metrics among them, debt-to-EBITDA. So they're intended to function together as the holistic evaluation of the balance sheet is considered.

Okay. Yes. I guess, my read into it was that the leverage target was implying that expect the additional asset sales beyond what's kind of implied in the absolute debt reduction target, is that not the right way to think about it?

We haven't given any hard dollar amount associated with either individually or any aggregate, the asset sales processes we have underway. So I'll defer that to you to assign whatever evaluations you'd like to the packages, but suffice it to say, again, it's about crystallizing the value of non-core assets or assets where that capital can be better deployed elsewhere in Range.

We are nearing the end of today's conference. We will go to Kashy Harrison of Simmons Energy for our final question.

So I had a quick follow-up for Alan. You gave some really great color on incoming ethane demand. I was just wondering, in your opinion, and just your global experience in the field, do you find the forward market trend sales to be more, to be fairly efficient? And do you think there is properly pricing in that demand? Or do you find the forward market could be or maybe perhaps a bit more volatile? And then kind of tagging onto that, does the 36% of TI assumption bake in your expectation for improving ethane demand? Or is that just based on whatever you are seeing in the forward market?

This is Alan. It's a good question. Forward curves for natural gas liquids -- speculating on natural gas liquids aren't quite as liquid as, let's say, natural gas or crude oil. And similar to natural gas though the activity down the curve is largely producer driven activity. The chemical players in the market, those that are naturally short and that are physical buyers of the products aren't active hedgers maybe because they have a spread that they would need to hedge and the polymer markets are even less liquid, let's say, than the NGL markets. So for that reason, the shape of the curve often is dictated by the trading activity in people's view of the market but to a large extent also by hedging activity of producers. So to answer your question, no, I don't believe it's always a good guide of what forward prices are actually going to be. It shifts what today's value is that you can get the market for that forward strip. So our guide is based on the strip and I would say with reference to the numbers that we've published, we believe that there's upside to that guide for all the reasons that I mentioned in my -- in answering that previous question around ethane, propane and butane. Does that answer your question?

That does. thank you.

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

I just want to thank everybody for participating on the call this morning and feel free to follow up for any questions that you might have with our IR team. Thank you.

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