山脈資源 (RRC) 2018 Q3 法說會逐字稿

Welcome to the Range Resources Third Quarter 2018 Earnings Conference Call. (Operator Instructions)

Statements made during the 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 third 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.

Lastly, as a bit of housekeeping, I'd like to point out that starting in 2019, Range plans to release hedging gains and losses ahead of each earnings report in a filed 8-K. We believe this will help reduce variability in estimates and assist in the calculation of realized prices each quarter.

With that, let me turn the call over to Jeff.

Thanks, Laith, and thanks, everyone, for joining us on this morning's call. Range made steady progress in the third quarter on the strategic goals and 5-year outlook we provided at the start of 2018. We hit our production targets within budget, we generated free cash and we accelerated our balance sheet improvement with the recently announced sale of a 1% override in Washington County for $300 million.

Looking at the third quarter results. The team continued to build on the operational and financial success we saw in the first half of the year. Our cash flow increased 27% over the prior year. This was driven by improved pricing and consistent operational execution.

As one of the largest NGL producers in the U.S. with direct exposure to international markets, Range was well positioned to capitalize on improved NGL pricing fundamentals. You might recall that last quarter, we increased our full year guide for NGL realizations. With our unique advantage as an NGL producer with direct access to multiple markets, we're again increasing our pricing guidance and expect fourth quarter realizations to be approximately 40% of WTI.

In the third quarter, 47% of Range's pre-hedge revenue came from liquids, the majority of which was from our Appalachian NGL production. Appalachia is in a differentiated position in the U.S. as it relates to NGLs with in-basin fractionization, control of purity products and producer access to international markets. This type of market does not exist in any other major U.S. liquids play as other basins typically send a Y-grade, or unfractionated, barrel to the Gulf Coast with no control over where it's marketed. Last quarter, we mentioned that we thought the benefits of the Appalachian NGL model would become evident over the next year or so. We think that Range's third quarter pricing strength and our pricing guidance for the fourth quarter highlights that differentiation.

Range's natural gas differentials also improved versus expectations during the third quarter as Rover capacity came on in September, transporting Range's gas to the Gulf Coast and Midwest markets.

Range is also seeing significant improved in-basin pricing compared to last year as the Appalachian gas market is benefiting from new pipeline capacity additions in both Northeast and Southwest Pennsylvania. As a result, Range expects our natural gas differential to improve to $0.12 per Mcf less than NYMEX in the fourth quarter. This improves our full year guidance to NYMEX less $0.08. Over the next couple of years, we expect basis to remain strong in Southwest Pennsylvania as additional pipelines are placed into service that will keep that portion of the basin free-flowing to other markets.

Pricing in Northeast PA will depend on growth profiles of the various producers. However, near-term basis has recently improved in that area to levels not seen since 2013.

Operationally, the team continues to push for efficiencies, setting records on drilling longer laterals and turning in line high-quality Marcellus wells. In fact, Southwest Pennsylvania's third quarter production was approximately 29% higher when compared to this time last year. I believe the significant growth out of Southwest Marcellus, while living within cash flow, demonstrates what our core assets are capable of, which provides us great confidence in our long-range plans.

Turning to the 5-year outlook. I think it's important to reiterate that one of our key strategic objectives was improving our leverage profile. We believe that prudently lowering leverage is a key step in what we think is a compelling 5-year plan that delivers a competitive free cash flow yield with an expected $1 billion in free cash over the next 4 years.

We're pleased that with the announced overriding royalty sale and corresponding debt reduction, combined with improved liquids pricing and consistent operational execution, is expected to bring Range's leverage below 3x by year-end 2013, approximately 2 years ahead of schedule. This places Range in a great position to execute on our long-term plans of consistent growth in cash flow per share. Range is actively pursuing additional asset sales as a way to accelerate our path towards further balance sheet improvement and the return of capital to shareholders.

Looking at the base case 5-year outlook, we anticipate expanding margins through a lower cost structure as Range leverages its high-quality inventory in existing infrastructure. These unit cost improvements are led by reductions to our GP&T costs through increased utilization of existing transportation, gathering and processing capacity.

We also expect a meaningful reduction to interest expense per Mcfe as we increase cash flow and reduce debt, bolstered by asset sales like we recently announced. At the same time, G&A per Mcfe should improve as we become more efficient and leverage our existing personnel. Combined, we see these cost reductions equating to enhanced margins over the 5-year outlook. Third quarter cash unit cost improvements for G&A and LOE were evidence of this trend. As we fill our Rover capacity, the last of the natural gas firm transportation agreements will begin to see improvements in margins on our Marcellus natural gas sales as well. We believe this anticipated improvement in margins, coupled with Range's low decline rate and correspondingly low maintenance capital, positions us to generate sustainable free cash flow. And given our vast inventory of high-quality Marcellus locations, we believe we're in a unique position to not only deliver on a planned free cash flow and growth but to continue this beyond the 5-year outlook into a market that will see others exhausting core inventories. In fact, I believe that Range has the best natural gas assets in North America when you consider 5 important factors, and that's quality, quantity, infrastructure, liquids optionality and stacked pay.

As I said on the last call, the entire Range team, from the field to management to the board, is focused on translating our incredible inventory into shareholder value. I'll now turn the call over to Dennis to discuss operations.

Thanks, Jeff. The third quarter was successful operationally, with capital spending on track and production coming in better than expected. Third quarter capital spending of $205 million and year-to-date capital of $725 million puts us comfortably on track versus the 2018 budget of $941 million.

Production for the third quarter came in at 2.27 Bcf equivalent per day or about $50 million better than planned as a result of exceptional well performance and increased ethane recovery.

Looking first at ethane. Our marketing team is always looking to maximize Range's cash flow by selling ethane barrels for more than we would otherwise receive by selling ethane in the gas stream. In the third quarter, we clearly saw improved NGL pricing across all products. And in particular, we saw ethane prices improve substantially in September. The marketing team did a great job selling additional ethane barrels above our contracted capacity during that quarter. This allowed Range to increase quarterly cash flow and recover approximately 15% more ethane than we did in the first half of 2018.

Looking forward, with ethane prices now at levels that incentivize most producers to extract additional barrels, there are limited opportunities to increase ethane production above firm capacity in existing sales arrangements. However, the Range team will be persistent in looking for those opportunities on a daily, weekly and monthly basis. And with a history of consistently moving over 60,000 barrels per day with direct access to 3 ethane outlets in Appalachia, along with having an in-house marketing team with relationships in the U.S. and abroad, we see Range being positioned very well to benefit from improved NGL pricing in the U.S. and the international markets.

Next on the list, we also continue to see positive well performance from recent wells, which drove incremental production for the quarter. One example is in the Appalachia dry gas area, where we turned to sales 6 new wells on an existing pad with an average lateral length of over 12,300 feet. The average IP of these wells was 29.6 million cubic feet per day, resulting in yet another 100 million cubic feet per day pad. On top of that, we also observed continued strong performance from our 28 dry gas wells turned to sales in the previous quarter, which we touched on during our prior earnings call.

I also want to point out we are seeing very early and exciting production results from the 8 super-rich wells turned to sales during the quarter. For example, on one of our existing pads, we recently added 5 new wells with an average lateral length of approximately 12,800 feet. The average IP for these wells came in at 37.9 million cubic feet per day equivalent, which included an average condensate production over -- of over 1,000 barrels per day per well. In fact, at one point, the total combined condensate production from the pad peaked at 3,000 barrels per day. Plus, 2 of these wells alone with an average completed lateral length of a little over 18,000 feet were flowing at a combined volume of more than 2,450 barrels of condensate per day. These were the 2 longest laterals drilled and completed by our Appalachia team that we discussed earlier this year, with production results coming together in Q3.

As we enter the fourth quarter, we are scheduled to initiate sales on 22 wells, taking our turn in line total for 2018 to 92 wells. This is slightly lower than the 100 wells expected earlier this year. However, when looking at the completed lateral footage we plan to turn to sales in 2018, we will be within 2% of the original plan, all due to extending lateral lengths.

Fourth quarter wells will be focused on our wet acreage near the upcoming Harmon Creek processing plant, which is on schedule to be commissioned this quarter. This will help us fill our firm capacity into the Rover pipeline, which was put into service on September 1. As discussed on prior calls, Range has capacity on Rover of 400,000 a day, and we're currently on track to fill this by year-end.

Turning our attention to North Louisiana. We had one rig operating in the third quarter with sales initiated on 2 wells. We will continue drilling with this one rig for the fourth quarter as we evaluate well performance from the 2018 program.

With the overall plan clearly outlined, we set -- we will set production guidance for the fourth quarter at 2.255 to 2.265 Bcf equivalent per day, putting us on track for approximately 11% year-over-year growth. And as I mentioned earlier, our capital budget of $941 million remains on track.

Now let's shift to a topic that gets a lot of attention these days, and that's lateral length. We are really proud of the team's work in this area, and we think it's important to understand that the story here is about more than drilling longer laterals. It's also about overall program economics. When you break down the value of drilling long laterals, there are 3 areas to consider: development efficiency, well performance and capital efficiency. These are 3 key boxes we're checking for both improved well and program economics.

First, let's look at development efficiency and sustainability considerations. Simply put, this is our ability to maximize access to the reservoir with a single wellbore, allowing us to develop more acreage and resource from a much smaller footprint. This is important for Range and for the communities where we operate for what I think are obvious but often underappreciated reasons.

Horizontal wells and now longer laterals allow for more efficient development of acreage that otherwise may have been challenging due to several possible factors, including existing or planned surface activities, difficult terrain or environmentally sensitive or special use areas. With all that in mind, the takeaway is simple as it relates to developing our full acreage position. Longer laterals allow for more efficient development with a much smaller footprint. And again, this is an important strategy for both Range and the communities where we operate.

Second, there's well performance. It's still early in the game when it comes to evaluating well productivity for long laterals. But when comparing their performance to our more than 1,000 wells in the Marcellus, the production from our longer lateral lengths is consistent with our expected type curves for each area. And at this point, after careful routine performance analysis by our technical team and comparisons to the corresponding type curve, we have not seen an impact to normalized production associated with lateral length. That's after more than doubling our average lateral length over the past 4 years. So as we continue to evaluate our program well results, none of our reviews have indicated any inverse impact of lateral length to well performance.

Lastly, let's look at capital efficiency. Longer laterals can significantly reduce and even eliminate a number of costs in areas such as well pad and road construction, top hole drilling, drilling and completion mobilizations, surface facilities and reduced cycle times. For example, based on our current numbers, one pad with 4 18,000-foot laterals can be drilled and completed with up to a 20% reduction in total capital expenditure compared to 2 pads with 4 9,000-foot laterals covering the same acreage position.

Our industry is constantly evolving. Innovation and advances in horizontal drilling efficiencies over the past several years have driven an increase in the footage that we can drill in a single day. We are now at the point where the time to drill an additional 5,000 to 10,000 feet of lateral length may only be a couple of days requiring minimal incremental capital to be spent. And the wells we are drilling with laterals longer than 15,000 feet have shown as much as a 30% reduction in a lateral drilling cost per foot.

Our ultimate measure of success is economic performance, and our analysis consistently indicates that wells with longer laterals provide better returns. These higher returns directly translate into greater value for our shareholders. Given Range's asset quality and technical team, we believe drilling long laterals gives Range a competitive advantage as we move forward.

I'll share a few more notes before we head over to Mark. While our plans for 2019 are far from being finalized, we are in the process of identifying growth opportunities, milestones and projects that keep us in line with the objectives described in our 5-year outlook. As we look toward the coming year, we expect to continue our practice of drilling longer laterals to generate improved returns and value.

Similar to 2018 and prior years, we plan to drill wells on pads with existing production when possible as that allows us to take advantage of reduced cycle times and existing infrastructure. Also, with the Harmon Creek plant on schedule for service before the end of this year, we are anticipating a full year of incremental processing capacity for 2019. This will be further supported by additional compression that will be added to our Southwest PA program during the second half of 2019.

The additional processing and compression capacity complements our plans for shifting towards more liquids-focused drilling in 2019, which takes advantage of improved NGL fundamentals and Range's differentiated access to NGL markets. We expect that next year's well mix of wet and super-rich wells could increase to as much as 75% of our Marcellus well count, up from 60% in 2018 and the highest percentage in recent years.

And I'll close out with this. As we enter the last quarter of the year, we are on track to deliver on our cash flow, leverage, capital and production targets as we drill and produce our most cost-effective and operationally efficient wells.

Now I'll turn it over to Mark so he can discuss the financials. Mark?

Thank you, Dennis. Business was well executed during the third quarter, accomplishing planned objectives while taking advantage of market opportunities. Third quarter activity continued to demonstrate Range's efficient operations and quality inventory, the combination yielding competitive and improving financial results. We've also made progress on strategic objectives, completing an asset monetization at an attractive price, realizing the value of a modest portion of inventory and strengthening our financial position. As Dennis described, our operating activity remains in line with the 2018 plan and importantly, is delivering on budget.

Range generated free cash flow during the third quarter, fully funding the capital program while reducing borrowings. Analyst cash flow for the quarter improved 27% to $260 million. Cash flow improvement was driven by production growth of 14% and higher margins per unit of production, up 13%.

Cash margins continue to benefit from improving realized prices for natural gas and NGLs as well as efficiency on the cost side. Average realized price per Mcfe, pre-hedge net of transportation costs, improved 20% or $0.34 per Mcfe year-over-year.

Direct operating and corporate cash costs improved, declining a total of 16% or $0.10 per Mcfe. As we've mentioned historically, gathering, processing and transportation as a stand-alone line item will vary over time as new infrastructure comes online, such as Rover late in Q3, and will also vary with NGL prices given a portion of processing costs are paid as a percent of proceeds. In other words, higher prices received result in higher processing costs but better margins. However, over time, the unit cost will trend down with full utilization of infrastructure and through balancing future opportunities for in-basin versus out-of-basin sales.

As you will recall from prior quarters, new accounting guidance changed the presentation of certain gathering, processing and transportation expense starting in 2018. The net impact of this change is neutral to margins with offsetting increases to revenue and to GP&T expense of $0.23 per Mcfe during the third quarter. Adjusting this item for comparability, third quarter GP&T was $1.23. Year-over-year change is attributable to new capacity and higher NGL volumes and prices.

Turning to the balance sheet. Leverage as measured by debt to EBITDAX is down quarter-over-quarter and reduced nearly half a turn from year-end 2017. With planned capital expenditures in line with the annual budget of $941 million, we expect to continue generating free cash flow for the remainder of the year, which will further reduce borrowings.

Just after quarter end, we announced the sale of a royalty interest for gross proceeds of $300 million, which further reduced bank borrowings and improved leverage, putting us on an expected path to leverage below 3x at year-end 2018. As discussed previously, there were multiple asset packages being marketed and certain discussions are ongoing. We remain focused on enhancing Range's financial position and driving leverage below 2x. While we can't comment on timing, to accelerate deleveraging beyond the impact of organic free cash flow, we continue to evaluate divestiture options based on asset valuation and what we believe will drive the greatest long-term shareholder value.

We will continue to employ a rigorous and thoughtful capital allocation process with spending defined by cash flow generation. Once Range achieves leverage below 2.5x, we will be in a position to evaluate the relative investment returns from drilling, repurchasing shares and/or increasing the dividend. This will all be considered in the context of driving consistent, competitive shareholder value from a solid financial foundation.

Jeff, back to you.

Operator, with that, we'd be happy to answer questions.

(Operator Instructions) The first question is from Bob Morris of Citi.

Dennis, I just -- on the processing capacity, as you bring on the Harmon Creek and other capacity, you said you'll be at full capacity for processing next year. I know right now the fractionation capacity in the region is tight. And right now, I think you have the capability if you had the outlet to extract another 800 or 1,000 barrels per day of ethane. But as you look to 2019, what is the ability -- or the infrastructure there to continue to extract more ethane as you move up to 75% of your wells being in liquids areas? Or are you going to be constrained in any incremental or additional ethane extraction in 2019? I know in the meantime, you can go ahead and rail the butanes and propane to markets. But as far as ethane, will you have the ability to extract incremental ethane next year?

Yes. Great question, Bob. We've got our VP of NGLs Marketing here with us, Alan Engberg, and I'm going to pass the torch to him and let him tackle multiple topics there.

This is Alan. Yes, a couple different questions in there. I'll try to get them. If I miss one, just let me know. But with Harmon Creek, we will actually be bringing up a 20-a-day DF at that facility. So as far as I think one of your questions relating to the ability to extract ethane with the new gas plant, there won't be any issues there. Relative to overall fractionation capacity in the basin, as far as Range is concerned, we're actually in a very strong position that way. And in fact, our friends at MarkWest are bringing up a new 60-day frac at Hopedale. I think it's planned for the month of November. So we'll be in a good position through 2019.

Okay. And then -- that's helpful. Dennis, the second question is just on the well outperformance. Apart from extracting more ethane, you mentioned the dry gas areas, you're continuing to see better performance on a per lateral foot basis. What is driving that? Because I don't recall that you've changed your completion design as far as number of frac stages or proppant loading. So what is sort of driving that continued outperformance or improvement in performance on the wells in the dry gas area?

Well, we've seen a couple of changes across the board. And I would say, the playbook is real similar that we deploy, whether it's wet, dry or super rich. And it's great technical work by our geology team looking at how we can improve our landing in the respective areas, analysis by our reservoir group to also look at what's driving well performance, and there have been fluctuations in sand loading. So, though we don't always comment on how we're tweaking, testing or changing the recipe for how we complete wells, there's always stuff going on in the background that we're looking at to try and improve the well results. So I would say it was a combination of those respective items.

Your next question comes from Holly Stewart of Scotia Howard Weil.

Maybe just a couple of questions on the NGL side. The realizations, obviously, looked very good for the quarter, and it looks like you're anticipating another strong fourth quarter. Would be interested, I guess, in just hearing your thoughts on the market overall. Maybe this is even directed at Alan. But in general, we've seen some product weakness in the last couple weeks. So is that factored into your thoughts around 4Q? And then maybe what are some of the pricing drivers here going forward?

Thanks, Holly. Yes, it's -- definitely, some volatility has returned to the market. No question about it. Actually, prices that you saw during the third quarter went up very quickly. So with respect to ethane, that pretty much trades on its own outside of crude oil, but it was on a tear, and the rest of the NGL barrel with crude continued to do well. And then based on tightening fundamentals across the NGL barrel, we actually saw some nice prices. You could argue prices almost for ethane, in particular during the third quarter, almost went up too much too fast. We're due for correction. We got that correction in spades. I'd argue that it's almost come down too much too fast. But nevertheless, the overall fundamentals haven't changed. And the fact of the matter is that we've got a lot of new demand coming on. In fact, at the end of this year, we've got a brand-new steam cracker coming on that will be roughly 90-a-day of ethane demand. And then if you look through the rest of, let's say, the first quarter, I think you've got roughly 280,000 barrels a day of ethane demand coming on stream. And we just don't have at this point the infrastructure to supply into that demand. So you've got pipeline tightness out of the Permian, out of the Midcon, that is one issue. And then the further issue, of course, is fractionation capacity in Mont Belvieu. And neither one of those actually debottlenecks in time to meet that demand. So I think the overall fundamentals will remain tight for ethane as well, and it's not talked about that much, but I think also for the rest of the NGL barrel. So the stocks that we see reported by the EIA today are a combination of the product as a purity molecule as well as a product in Y grade. And I would say that the balance is shifting to more Y grade going into storage than what purity products are going into storage. So that's a recipe for a stronger market that, despite the volatility that we're seeing right now, should translate into higher prices.

And then if I might, our guidance for the fourth quarter is simply going to be based off of strip pricing. So to the extent that we see strength like Alan is talking about, that would be upside to the guidance that we provided in the fourth quarter.

That's great. And then maybe just one more, a little -- maybe this is for Mark or Laith, a little more granularity on just the costs related to that, the GP&T and C line item. It looks like the -- your forecast, see an increase quarter-over-quarter sort of due to that -- due to NGL pricing as well as your incremental transport. But could you just maybe talk in general terms about how this guidance is translated? So if that means some color around what percent of your processing contracts are POP versus C. Or maybe even a breakdown of that $1.54 in cost. What part is transport? What part is gathering, et cetera? That would be helpful.

Holly, this is Mark. Yes, let me take a crack at that and let's take a step back and give a snapshot of where we are just as a reminder. So the reported number was $1.46 an Mcfe for this quarter. Adjusting for the accounting change, we're at $1.23. So for comparability, the change, thus far, looking historically, has been to additional capacity coming online and of course, additional NGL volumes extracted as well as the higher NGL prices. So as we look at those factors as they apply to Q4, you're seeing a continuation to a degree of new capacity in the form of Rover being on for a full 3 months as opposed to just part of September. That's a good portion of it. You have continued strength on NGL prices and volumes that are being moved. So those are driving the increase quarter-over-quarter. When you adjust for that accounting change, we are peaking roughly where we said we would, and it will peak on a per unit basis, gathering, processing, transportation expense. In the first full quarter after Rover, our last currently signed contract comes online. So the trend is as expected. As you look at the total number and try to break it down into its components, big picture, roughly 20% of the cost on a per unit basis relates to processing. And then the balance is split roughly between long-haul transport and gathering. So as we look out further into the future, the trend line we laid out in the 5-year outlook still applies. The numbers have changed, obviously, with accounting guidance implementation in presentation, but the $0.25 improvement we indicated in the 5-year outlook still holds and is still part of our expectation. And keep in mind that those comparisons were averages -- annual averages. So as you think about it from peak to trough from a quarter, perhaps next quarter, you should see at least a $0.25 per Mcfe improvement, if not better.

Your next question comes from Ron Mills of Johnson Rice.

Jeff, maybe for you on the overriding royalty interest sale, how did you all arrive at a 1% override interest sale? What positioned you to be able to pull that lever? And then as it relates to that, how does -- how do you think this puts you in terms of whether leverage or negotiating position on your additional asset sales that are planned given the liquidity you've already brought in?

Well, let me answer the second question first. It puts us in a strong position. Our target -- short-term targets that we've talked about now for the last couple of quarters and in our incentives was to exit this year below 3x. So we've been able to do that. We're on track to do that. And obviously, being in that position of not having to do something puts you in a better position with all other asset sales. So it puts us in a good position. Organically, the 5-year outlook that we laid out will pull leverage forward 2 years. The pricing in that outlook, really, if you look forward, based on the comments of where we are and the comments that Alan Engberg just laid out, puts us in a good position with the 5-year outlook. That said, we're still actively looking at asset sales, and we -- to go back to the first part of your question, we looked at a variety of options and -- to look at where can we get the best value and best valuation. And we think with that overriding royalty sale, we got a very strong valuation for it. We have a high net revenue interest, and our wells have very strong economics. So we thought of the variety of things we're looking at to that point in time, that was the right thing to do.

And can you -- especially as it relates to Northeast PA, which has been one of the assets being marketed, any color -- maybe it's on the -- more on the marketing side, on what the pricing has looked like since the start-up of Atlantic Sunrise? Because it also seems from a timing standpoint that once that is fully up and running, that the market availability of that could even improve further. Is that fair?

Yes, I think that's a good point, Ron. With Atlantic Sunrise on, basis has come in significantly. I think recently, it's literally been in the $0.33, $0.34 range. And historically, it's been much higher than that. So cash flow, therefore, is stronger as they're high-quality properties. I think when you're looking at asset sales and if you look at historically, Range has sold a lot of assets. But we've said this numerous times, you really have to find the right buyer at the right time. So clearly, that pipeline coming on helps.

Your next question comes from Matt Portillo of Tudor, Pickering, Holt.

On Slide 7, you highlight the potential to ramp volumes through 2022 and thereafter, generate a material free cash yield that looks to be north of 30%. As you look at the forward curve for natural gas, the market concerns around supply exceeding demand over the next years and the hyper focus on balance sheet improvement, is there a case to be made to potentially pull forward that free cash flow inflection into 2019 and 2020 and move closer to maintenance CapEx until there's a more constructive view on the commodity on a go-forward perspective? And specifically around that, just the potential to accelerate shareholder returns, buying in reserves at a relatively cheap valuation here on a go forward perspective.

The short and simple answer to your question is yes. There is a case and a scenario where you have to evaluate that as a potential outcome. So just as a reminder to everyone or new folks to the story, the 5-year outlook is just that, it's an outlook. It is directional and what the asset base is capable of under a particular scenario. It's not intended to convey our plan or our conviction on one particular path. So we continue to evaluate the economics of the drilling program to rightsize that program based on competitive and recurring drilling opportunities. So as we get a sense of how 2019 is going to shape up from a pricing perspective, what returns we can help secure and derisk for hedging, we also have the exposure on NGLs and how does that relate to cash flow. So the gating item as it relates to buying back in reserves, as you put it, essentially repurchasing shares, really, the gating item there is the balance sheet. So the multifactor equation, if you will, is balancing the best rates of return for reinvesting cash flow, how much of that cash flow to reinvest that achieves balance sheet objectives while maximizing shareholder return. So a long-winded answer to your question, but we're in the midst of the planning process, and we look forward to delivering that plan early next year as is our typical timing.

Your next question comes from Paul Grigel of Macquarie.

In a similar vein, as you guys move towards 2.5x either from greater organic free cash flow or asset sales, what's the internal discussion on balancing further debt reduction versus either a repurchase of shares or increasing the dividend? How do you balance those items in terms of priority?

So once you get to 2.5x, I think we're -- and below, you're more in a comfortable zone provided it's sustainable based on pricing expectations, hedging and so forth. So the size, timing and scale of any repurchasing or a dividend increase is -- it would be some combination that could start around that level. And of course, your opportunity and sizing increases as you get closer to your longer-term leverage of 2x, and that's sustainable. So no particular numbers for you there, but it's about balancing the return. So the other factor there is what is the stock price at that point in time, what is the incremental cash flow per share generated by repurchasing shares, what is the rate of return on purchasing shares versus drilling another well. So there's a quantitative analysis, there's math that has to be done when you get past those gating items.

And would it be fair to assume -- as a follow-up on that one, would it be fair to assume that the leverage target that was in this year's incentive plan rolls over into next year? Is that -- obviously, at a lower level, but would that be fair? Is that too premature at this point in time to assume that?

I think the metrics you've seen in the incentive programs, you've seen them evolve and continue to align shareholder interests with the objectives of the company. So you can expect those to continue to evolve and drive appropriate strategic objectives for the company in line with what's going to drive the greatest value for the shareholder. So you will expect to see those and see those appropriately adjusted.

Okay. And then just lastly, could you just provide an update on the EVP search and the latest thoughts on timing on when we could see something there?

Yes. The -- we've engaged a search firm and the process is underway. Of course, the important thing, whether it's the board additions or EVP, it's all about getting the right person. So -- but the process is underway, and I'll leave it at that.

Your next question comes from Kashy Harrison of Simmons.

Just one quick one for me. In the prepared remarks, there was some commentary on the exhaustion of core inventory within Appalachia, and I just wanted to dive a little bit deeper into -- just into that comment and that thought process. Specifically, what are you looking at that makes you -- that leads you to the conclusion that the core is being exhausted? What are some of the drivers behind that? And when do you believe it becomes more apparent to the broader market that there is less core inventory in Appalachia? Is that a -- is that within the next 5 years? Is that within year 6 through 10? Just some color on that line of thinking would be greatly appreciated.

Yes. I think if you go back, the discovery well for the play was in 2004. It was a Range well, began being drilled horizontally successfully correct by Range in 2007. A lot of other companies have jumped in and a lot of wells have been drilled. It's now the largest gas field in North America, I believe the largest gas field in the [work overview] consider the area. So the cores of those plays are really well-known, where the better wells are and where the poorer wells are. I don't think there's any question when you look at the quality of the wells, whether you look at the absolute recoveries or normalized recoveries or recoveries per thousand, however you want to look at it. And if you look at where people have been drilling and where the -- all the activity has been, a lot of it's been in the core. People talk about technology and technology will continue to evolve, and we're not questioning that. But you can take state-of-the-art technology and pump that in Centre County or you can pick the county of your choice and the wells still aren't very good. So -- in fact, they weren't good at all. So it's important where you're drilling and where you are. So the acreage is leased. The cores are -- have been snapped up by various operators. I think Range has -- again, considering those 5 things, quality, quantity, liquids optionality, takeaway and stacked pay, I think we have the best position in the play. So the cores are limited, the cores are known, people have drilled water levels in them. And I think within -- you said in the -- is it in the first 5 or year 6 through 10, I think it's clearly within the first 5 you'll see that core exhaustion, and you'll start seeing it with deteriorating capital efficiency.

Your next question comes from Jane Trotsenko of Stifel, Nicolaus.

So we have seen several data points that the fraction costs are falling.

Can I ask -- can we ask -- you're maybe on speaker. It's hard for us to hear your question.

Yes. We have seen several data points that the fraction costs are falling. And my question is, how are the components of the well costs trending? And if we should -- and how should we think about well costs for the next year relative to 2018?

Jane, this is Dennis. I think as we look over the course of 2018, from a service cost standpoint, we've really seen, what I would say, is some very small increases, but they tended to be very kind of a line item in niche and nature. So fuel might be an example where we've seen some movement, and we've worked with our service partners to try and address some of those increases. As we talk about usually call in and call out, though, our efficiencies have really masked, and in some place, carried our cost even lower on a per foot and per well basis because of the great work that our operating and technical teams are doing. So at this point, we really haven't seen a cost increase when you look at, let's just say, total cost involved to land, drill and produce our wells. For '19, we're well in the throes of our bid process for our services for the upcoming year. We're excited about some of the early results. We'll have more to share as we get to the next call. But at this point, I think we're seeing encouraging cost that would keep us in line with what we were expecting and seeing here in 2018.

So would it be -- I probably have to say that you don't see like a major cost inflation happening in 2018 -- '19, right?

Well, I think at this point, again, it's early, but it would be difficult, I think, for us to see a significant cost increase for '19, again, based upon conversations with our service partners and early on results.

Okay, got it. My second question relates to the ethane recovery. I would like to understand a range of ethane prices that would make ethane recovery economics for Range Resources. And if we should expect a similar amount of ethane recovery in the coming quarters and maybe we could see a pickup in ethane recovery for Range once Mariner East 2 comes online and Mariner East 1 is converted to all-ethane pipeline, any thoughts about that?

Yes, this is Alan. As far as how we look at ethane recovery, typically, it's pretty -- in some ways, it's somewhat binary. You're looking at the local gas price versus the realized price after you get the ethane to the market. And again, fortunately, Range took a long-term view a long time ago, actually, at what the basin had to offer, and we made commitments to be able to move product domestically. So south down to Bellevue, up into Canada as well as internationally. So we have basically a range of options for moving a product. We look at the overall netbacks at each of those locations as well as in-basin, and we make a decision based on that of what's going to get us the maximum returns relative to natural gas. So that's, in a nutshell, how we look at things. As far as the Mariner system is concerned, as you know, ME2 is poised to start up soon, and it'll be carrying propane and butane as well as a C3+ Y grade. There will eventually be more capacity on ME1 for ethane. And overall, I think net-net, that's good for the basin, and it's good for Range.

Okay. And can you give us a range of ethane prices that would make ethane recovery economic for Range Resources?

It's all relative to where gas prices are, so I can't really give it to you on a flat price basis.

Okay. I see, I see. But generally speaking, we should see a similar amount of ethane recovery in the coming quarters as we have seen in 3Q, right?

That's a decent assumption.

The team had the ability in the third quarter to move some additional ethane when we saw the spike in prices in September. So the ability to move -- to do that again in October, November, December is going to be dependent on Alan and the team's ability to find additional outlets for that ethane. But as you can imagine, everybody is fighting for those same outlets.

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

If I could go back to the royalty sale, how deep is this market? And a related question would be how should I think about the implied cost of capital in the sale? Your debt trades at 5%. Your equity trades at 6x EV multiple but -- and then I've got a follow-up question as well.

Rehan, this is Mark. Let me take a stab at that question. So how deep is the market? There was a very active set of dialogues around the marketing of that royalty interest, so there's clearly an interest in royalties as an investment opportunity. You can look at the other structures, whether they're publicly traded or in private hands, that investors do have interest in yield-oriented instruments. And particularly, in something like this, it's a high-quality asset that has cash flow generating ability that is a growth component. So there is some depth to that market. As Jeff has mentioned before, in our divestiture processes, it's about finding the right and the best buyer for that asset, which brings you to valuation. So in terms of getting a fair price and a good value for something like that, of course, the universe is smaller for those that are going to pay what we believe is a fair and accretive price to us. But suffice it to say that there is a viable and healthy market there as it relates to royalty. And the second part of your question?

What's the implied cost of capital for kind of what you just transacted?

Sure. Well, I mean, the most simplistic way to look at it, look at the estimated $25 million in cash flow, look at this as a yield, look at the $25 million in cash flow relative to the gross $300 million, you're at a 7% yield. As that compares to Range's cost of capital, that's an attractive rate at which we could divest such an asset. And to think about it relative to cost of capital, I would think about it relative to the NAV of the asset. The trade here was an asset sale and the monetization of an asset at a particular price assumption and a particular development plan, productivity basis and so forth. This was not a trade of some percentage yield for 5% debt. This was monetization. It was a straight asset sale. It had the added benefit that further improved the yield -- the effective yield and improvement in cash flow deleveraging to Range for the paydown, but it's certainly not a high double-digit type of cost of capital.

So on that kind of depth to the market front, over the next 2 years, if you get the same kind of, call it, multiples, would you be able to do something like $1 billion worth of sale along the same line, same valuation if you so choose to?

I don't want to draw any boxes or book ends around that. I would just say that generally speaking, we would evaluate assets in the portfolio and see what the most effective way to monetize and create value for the shareholders. So whether that's holding and developing it or whether that's perhaps halving something off, whether it's acreage, whether it's a producing piece of the asset portfolio or whether it's royalty, we would consider most options at the right valuation.

I apologize for one more question. So let's just say winter shows up. Storage is low, the exit low, gas prices next year strengthen, my favorite number is $3.50, call it, how do you think kind of -- what is your capital allocation kind of shift looks like? And maybe, Jeff, if you can kind of give some color on how do you think the industry responds, maybe the northeast, the Utica, the dry gas and the kind of southwest wet area, if you can break it down into those buckets?

Yes. Well, first of all, let me say I like your prognostication there, $3.50. So we'd be thrilled with that -- a higher gas price and -- which I think we've been clear about this. If prices are higher, it will allow us to delever faster and get to the point of returning capital or continuing to delever faster. You won't see a ramping activity. You'll see us delever faster with the incremental extra cash flow, which would be great. There's a strong message really I think in the industry from the buy side, I think a clear message, to the producers to, call it shale 2.0 or call it whatever you want, to not ramp activity but to live under cash flow, really, and then return capital back to investors and work on returns. So I don't think you'll see a big spike in activity. It's interesting, if you look at the rig count in Appalachia, it's really been fairly steady or steady to down, if anything. And I think even with the spike -- and you're talking about a spike also. The question is, if sustainable prices long term, could you hedge and lock it in? Right now, the curve is very backwardated. And I've read your research, and I think there's -- it's a very well thought out research. And if what you're saying is true, the back end of that curve at some point should come up, maybe people would think about it differently. But in terms of a short-term spike, I just think we have incremental cash flow, we delever quicker.

We are nearing the end of today's conference. We will go to Biju Perincheril of Susquehanna for the -- for our final question.

My question was with the success you're having with the longer laterals, can you give us some color on how that trends up over the next few years, your average lateral length? And what impact does that have on your base declines and how we should think about maintenance capital?

You bet. So our 5-year outlook was based on an average 10,000-foot lateral. And at this point, we're planning to still adhere to that on an average basis. What we know is, and I kind of mentioned this earlier, the results are early and they're exciting, both from a well productivity standpoint, the cost reduction that we're seeing and some of the efficiency gains. So we're walking our way into not just trying to drill record wells, but also have repeatable success, which that's a real strong key in unconventional resource development. So as we look forward into 2019 and the years beyond, when we factor in more long laterals, the short answer is yes. It's going to be real key for us. Anytime we start to look at drilling, let's say, we have drilling successes over the last couple of years to get to 15,000 feet, now to 18,000, we will take our division teams, we'll take a look at the appropriate adjustments that we would want to make to our long-range plan, and then how that feeds into the 5-year outlook. So as we look forward, we're excited about drilling longer laterals. We think it's going to be a much more efficient use of our footprint. And as I mentioned earlier, that's key for us and also for the communities where we operate in. But are we shifting to a much bigger number at this point? I think the short answer is no until we see longer-term results and until we can see how that plays into our long-range plan.

When you look at -- if that number does go up, is that going to have an impact on the PDP declines when you mentioned earlier in the prepared remarks normalizing per lateral length the productivity? Is that on the initial production rates or on where you think the EUR will be?

Well, I'll tackle it from 2 pieces. The EUR piece, we're -- again, we're not seeing any change in EUR per thousand foot basis as we look at the early on evaluation of these wells. Again, it's early. The first 18,000-footers are just coming online in this -- in Q3. The good news is as we have some 15,000s and a little bit longer that have been in production for now, somewhere in the labor of in excess of 12 months and the results there are really encouraging. So they're in line with what we've showcased as our area type curve, so 2 thumbs up on what we're seeing from a well performance standpoint. Will it keep our base decline flatter? As you look at 2018, I think we've communicated we're anticipating our PDP decline to be corporately around 23%, and then that flattening into '19 close to 18%. So if -- longer laterals will allow us to keep our infrastructure utilized longer, some of the wells will be flowing at some restrained rate. So I think we would expect, yes, our PDP decline to look flatter in the years ahead with longer laterals.

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.

I'd just like to thank everybody for taking time to participate in this morning's call. Thank you.

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