Range Resources Corp
NYSE:RRC
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Range Resources Corp
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Welcome to the Range Resources' Fourth Quarter and Year-End 2017 Earnings Conference Call. All lines have been placed on mute to prevent any background noise.
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. After the speakers' remarks, there will be a question-and-answer period.
At this time, I would like to turn over the call 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 Year-End Earnings Call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Ray Walker, Chief Operating Officer; and Roger Manny, Chief Financial Officer.
Hopefully, you've had a chance to review the press release and updated Investor Presentation that we posted on our website. We also filed our 10-K with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system.
Before we begin, let me also point out that we will be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. In addition, we've posted supplemental tables on our website to assist in the calculation of these non-GAAP measures. The supplemental tables also provide calculated natural gas differentials for the upcoming quarter and detailed hedging information for all products.
With that, let me turn the call over to Jeff.
Thanks, Laith, and thanks, everyone, for joining us on this morning's earnings call. As we begin 2018 and we look at what the next several years hold for Range, we're excited about what we see as we begin to harvest the top tier inventory that we've captured since discovering the Marcellus in 2004. We see this translating into improved returns and free cash flow laid out in our five-year outlook.
Before we discuss the great opportunity we see going forward, I'd like to acknowledge that our performance in 2017 was not up to Range's standards. While we had outstanding results in the Marcellus, we did not hit our targets in North Louisiana and we all agree yearly results have been disappointing.
The productivity of the wells has been below our expectations, and this is reflected in the updated type curves that we provided last month. Put simply, the asset has been more geologically complex than anticipated and portions of the core area have been less productive than expected. And while we have a very talented hard-working team overseeing the assets, we are slowing our North Louisiana activity significantly in 2018 and allocating approximately 85% of our capital to the Marcellus.
By slowing down in North Louisiana, it will allow the team additional time to incorporate our latest technical and production data. By allowing more time running just one rig for the remainder of 2018, we expect the team under new leadership will make improvements. Throughout 2018 and going forward, we will continually assess our capital allocation and make adjustments as needed.
From where we sit today, running one rig in North Louisiana and focusing the vast majority of our capital towards the Marcellus is the right move for Range. By focusing our capital in the Marcellus, we expect to generate Southwest Pennsylvania growth of 25% in 2018, allowing Range to fully utilize its transportation capacity. The ability to fill our firm transportation commitment so efficiently is a testament to the collaborative efforts of our marketing, planning and operational teams.
The Marcellus has continued to surprise us to the high side in terms of productivity and efficiency gains, as evidenced by the consistent reserve growth and production results over the last decade with improved type curves over time, most recently in the super-rich area that has continued to outperform our expectations.
Couple all of this with improving local differentials and a class-leading inventory of 3, 800 wells is why we're allocating approximately 85% of our capital to the Marcellus and why it is the driver behind the five-year outlook we recently provided the market.
Looking at this five-year outlook and beyond, I believe Range is very well-positioned to drive long-term value for shareholders with the focus on delevering and returning capital to shareholders. As we discussed on the last earnings call, Range has spent the last 10-plus years taking the Marcellus from an idea in a Range conference room to what is now the largest gas field in the country. This commissioning phase for Range is largely complete in 2018 as the last of our natural gas infrastructure projects comes into service, allowing us to deliver natural gas to customers from Appalachia to the Gulf Coast and abroad.
Over the course of the five-year outlook, we see continued improvements to margins through a combination of improved access to markets and an improved cost structure, driven primarily through better utilization of existing transportation and gathering capacity. Range's five-year outlook delivers an annual production CAGR of approximately 13% on a per share debt-adjusted basis.
Importantly, the outlook also provides approximately $1 billion in free cash flow and leverage below 2 times by 2022, all at year-end strip pricing and without the benefit of potential asset sales. This not only shows our commitment to spending within cash flow, but also the deliverability of our assets led by the Marcellus where the team has a great track record of delivering consistent results.
Switching gears and looking at the balance sheet, know that we're committed to prudently improving debt-to-EBITDAX below 3 times as quickly as possible. Like I mentioned, the five-year outlook has us improving leverage organically to under 2 times by 2022 without the benefit of potential asset sales, but our plan is to use asset sales to accelerate the deleveraging process and that's something we are actively pursuing.
Any additional cash flow from increased commodity prices or additional capital efficiencies will go towards our near-term delevering goals. In 2017, we sold $70 million worth of assets as part of our continual high grading, and we currently have processes underway for additional asset sales.
In addition to potential asset sales in the Midcontinent and northeast Pennsylvania, we're also looking at ways to pull forward the value on inventory that's not in our near-term plans. Before turning it over to Ray, I'll say what I think distinguishes Range is a very high quality and very large inventory. Evidence of this can be found in our five-year outlook and our recent reserves release.
At the end of the five-year outlook, Range would still have 3,200 wells remaining in the Marcellus alone. I believe the quality of our inventory is demonstrated in our year-end reserves report where proved reserves were up 26% over the prior year for Range.
The PV-10 of these reserves was $8.1 billion based on SEC pricing or $9.5 billion using year-end strip pricing. For context, our total enterprise value is trending at a roughly 30% discount to this PV-10, which doesn't include several thousand unbooked Marcellus wells or any of the potential we have in the Utica, Upper Devonian or Lower Cotton Valley. In effect, I see very little, if any, value being ascribed to Range's vast unbooked resource potential. It is on us, the Range team, to prudently and consistently execute and translate this resource potential into shareholder value.
I'll now turn the call over to Ray to discuss operations.
Thanks, Jeff. Starting with production, the fourth quarter came in at 2.17 Bcf equivalent per day, which resulted in 30% year-over-year growth. And the first quarter is off to a great start and we expect it to come in at 2.18 Bcf equivalent per day, which is inclusive of some planned MarkWest downtime that happened during January at the Houston complex, involving residue compression maintenance and upgrades for the new Houston 1A plant that's being commissioned soon. This had an impact of about 30 million cubic feet equivalent per day for the quarter for Range. This was built into our 2018 forecast, and I'll add that the MarkWest team did a great job in getting all this work done as planned.
For the year, annual production guidance is set at 11% and our capital budget for 2018 is reduced from 2017 and is currently planned at $941 million, allocated approximately 85% to our Marcellus assets in southwest Pennsylvania. Around 91% of the total corporate budget this year is directed towards drilling, completion, facilities and pipeline infrastructure.
Like Jeff mentioned, in our recent reserves release, we reported a 26% increase in proved reserves to 15.3 Tcf equivalent, resulting in a year-end PV-10 reserve value of $9.5 billion using strip pricing from year-end and current sales contracts. Our drill-bit finding costs were $0.31 per Mcfe with 55% of our SEC reserves being proved developed, and our proved developed reserve life of 19 years remains exceptionally strong compared to our peers.
The average lateral length for existing proved undeveloped wells in the Marcellus increased by 26% to approximately 9,000 feet, with newly added proved undeveloped wells averaging over 9,500 feet. Over the past several years, the lateral lengths of our proved undeveloped locations have continued to progress longer, and I would expect that these lateral lengths, when drilled, will on average be longer than they're currently booked.
We also had positive performance revisions for 2017, as improvements in well performance in the Marcellus more than offset the underperformance in North Louisiana that we previously discussed. Over the last five years, our reserves have essentially doubled or increased approximately 7 Tcf equivalent, adjusting for acquisitions and divestitures. Page 6 of our presentation on the website provides additional detail on the depth and quality of our Marcellus inventory.
As we've discussed on previous calls, over the last several years, Range has drilled some excellent wells on the north, southeast and west portions of our southwest Pennsylvania acreage position that further confirm the high quality of our core Marcellus acreage. The consistent success and continued improvement both in short-term rates and longer-term recoveries has all of us here at Range excited about the quality and scope of our future development potential.
So let me run through some highlights to represent some of the great things going on in Southwest Pennsylvania. During the fourth quarter, we turned in line 42 Marcellus wells averaging over 10,000-foot laterals from 10 different pads. When you look at the 30-day average rate to sales, again, remembering all these wells were under facility constrained conditions, these 42 wells on an average basis produced 23 million cubic feet equivalent per day to sales per each well. And, again, these are 30-day constrained rates and not just peak rates or IPs.
During the fourth quarter, we had four pads flowing at over 100 million cubic feet equivalent per day each pad to sales. These four pads were over that 100 million a day mark for each pad for periods ranging from 12 days up to 60 days and counting. One of those pads that's in our dry gas area produced to sales at over 170 million a day under constrained conditions for 14 days from five wells averaging 14,384-foot laterals.
Our corporate base PDP decline for 2018 quarter-four to quarter-four is expected to be approximately 23%. As we progress into 2019, our corporate base PDP decline will be decreasing to approximately 18%, allowing us to hold production flat with much less capital. Our Marcellus PDP decline rate is approximately 20% for 2018 and 17% for 2019.
As our production becomes more and more dominated by the Marcellus in Southeast Pennsylvania, our corporate decline rate will continue to flatten even more. At the end of our five-year outlook, we expect to be producing in the range of 3.5 Bcf equivalent per day, and we'll have the ability to hold production flat if we choose to with only about $600 million per year of maintenance capital, yielding $1.3 billion in annual free cash flow, as illustrated on slide 14 in the presentation on the website. And importantly, at the end of 2022, we will still have 3,200 high-quality Marcellus wells left to drill. We believe this sets Range apart from our peers.
On the drilling side, in Southwest Pennsylvania, we drilled 1.1 million lateral feet in 2017, which represents a new record and is a 30% increase in the footage drilled per rig over the prior year. The team drilled our top 15 longest Marcellus lateral lengths in 2017, with several laterals planned for 17,000 to over 18,000 feet in 2018.
In fact, just this past weekend, the team set pipe on a 17,875-foot Marcellus lateral, and the rig is currently drilling a planned 18,100-foot lateral on the same pad. Our internal industry research shows that we've now drilled the longest Marcellus lateral on record. While the average lateral length drilled in 2017 increased by 34%, importantly, the drilling cost per foot decreased by 16%. These drilling efficiencies have served to offset some of the increased service costs we've seen. This is reflected in our well economics that show improvement on a normalized cost basis in 2018.
On the completions and operations side of Southwest Pennsylvania, we completed a record 5,302 frac stages in 2017. The average lateral length of wells turned in line increased to 9,102 feet, which is a 42% increase over 2016. The average lateral length of wells turned in line in 2018 is expected to be 10,110 feet or an 11% increase over 2017. For 2018, we expect to drill approximately half of our wells on existing pads, which is up from a third last year.
The teams' efforts on water recycling have also benefited the company significantly as we are not only servicing our own wells efficiently with some of the lowest well cost in the area, we're also saving money by taking water from other operators in the area, reducing our cost further. On average, we have about $1.4 million in water costs per well, much less than some of our peers. And in Southwest Pennsylvania, our LOE decreased by 9% to $0.10 per Mcfe for 2017.
Concurrent with our recent reserves, 2018 capital and five-year outlook releases, we updated our type curves and economics in the presentation on the website, representing the average of the wells we expect to turn in line during 2018, as I just mentioned. And again, while we've priced in modest service cost increases of 5% to 10% in 2018, which mostly are on the completions side, we expect the net impact of those increases to be minimal in Southwest Pennsylvania.
Our technical team is also expanding its work with data analytics and predictive analysis, and we expect to see continued optimization from that work. Longer laterals, going back to existing pads and utilization of existing infrastructure, resulting in lower unit cost will also contribute to better economics and efficiencies in the coming years.
And finally, while not a lot of companies talk about it, I'm really proud of our teams all across the company when it comes to safety and environmental compliance. We had a great year in safety for 2017 with no days away-from-work and only one recordable incident for Range employees, taking us closer and closer to our goal of zero incidents and sending all of our employees and contractors home safely to their families each and every day.
On the environmental front, we focus each day on operating in an environmentally safe manner. For example, we've focused on minimizing methane emissions over the last several years. From facilities designed to testing protocols, we've made it a priority and have shared our efforts in the field with state and federal regulators. I am pleased to report that Range was recently recognized as a top performer in the area of emissions by As You Sow in its annual report, which can be found on our website.
Shifting now to North Louisiana, like Jeff said, the results we've seen thus far were not up to our standards. Our current plan is to run one rig for the remainder of 2018 with one frac crew on and off during the year as timing dictates. We'll continue to monitor capital and results and make adjustments as necessary. We'll continue to take what we learned throughout 2017 and integrate key drivers, such as landing target, job intensity, proppant placement, and stage spacing in the various layers in the Lower Cotton Valley.
We're incorporating seismic attribute data from the new shoots that we received near year-end and have developed more stringent reservoir and earth modeling. Bottom line, we're going slower and we have a dedicated technical team focused on improving the results we've seen to-date.
Shifting to marketing, during both the fourth quarter of 2017 and in early 2018, incremental firm pipeline takeaway capacity out of Southwest PA has commenced operations, which should improve our corporate differential significantly going forward. These projects include Enbridge's Tetco Adair Southwest Project, which went into service late in the fourth quarter, and TransCanada's Leach and Rayne XPress projects, which went into full service January 1 this year. And by the end of the second quarter when Rover is expected to be online, over 90% of Range's production will be directed towards price-advantaged markets.
Importantly, these additions to Range's transportation portfolio reduce basis volatility, especially during the seasonally weak months of July to October and should increase the predictability of Range's corporate natural gas differential going forward.
Looking at near-term Appalachia supply and demand, our internal work shows that when you look at the natural gas takeaway projects that have come into service since the third quarter of 2017, only about half of that volume is new gas, with the other half simply being local gas that was being displaced. More broadly, storage levels are likely to end the winter season between 1.4 and 1.5 Tcf, which will require a significant injection season to bring storage levels closer in line with the five-year average by the end of October.
At current forward pricing levels, coal-to-gas switching is incentivized, providing additional demand upside. Longer term, from the third quarter of 2017 through the end of 2019, we expect Southwest Appalachia takeaway to grow by approximately 12 Bcf a day with an additional 1.5 Bcf a day of demand growth from Cove Point and new gas power plant (21:32) over the same time period.
Consensus production estimates for Southwest Appalachian producers points to growth of 6.2 Bcf per day over the same time period at prices ranging from $3.07 to $3.09 per Mcf with WTI at $60 per barrel. And, of course, the current strip is not that high and might not support that level of growth. All of this supports the potential for improving local prices.
We're also seeing strong global LNG demand and we believe the U.S. is well-positioned to supply that increased demand. And specifically for Range, we believe our high-quality inventory and transportation portfolio positions us well to access this future demand growth.
Shifting to liquids, Range produced record volumes of NGLs in the fourth quarter of 2017 with total net NGL production of 106,038 barrels per day, up 24% compared to the prior year's fourth quarter, making Range one of the largest independent NGL producers in the U.S.
In fact, almost one-third of Range's expected revenue in 2018 comes from natural gas liquids, providing us leverage to improving liquids pricing, as evidenced in our five-year outlook sensitivities. As shown in the company presentation, if WTI were to average $60 over the five-year period versus strip pricing, which is closer to $54, Range would add an additional $700 million in cash flow over the next five years.
A significant portion of Range's ethane and propane volumes are being delivered to premium market segments via Range's advantaged access to international destinations. Fourth quarter Appalachian ethane gross prices were up about $0.25 per gallon, representing a 119% premium to local natural gas markets before hedging, and C3 plus NGL gross prices were $42 a barrel or 76% of WTI before hedging.
Propane, in particular, benefited from improving domestic and international fundamentals, with Range's realized prices up 59% over the same period in the prior year. Our top-tier inventory of liquids-rich assets have us well-positioned to supply both domestic and international projects coming on stream throughout this decade and the next.
Now, I'd like to turn the call over to Roger to discuss the financials.
Thank you, Ray. Reviewing the Form 10-K one final time last week, I could not help but notice the SEC required disclosure table on page 45. This table, as presented in all 10-Ks, sets forth the past five years of financial performance. Page 45 of the Range 10-K illustrates that since 2013, production has essentially doubled, proved reserves have essentially doubled, total unit costs per Mcfe have roughly been cut in half, profitability has been restored, cash flow from hedges has largely been replaced by cash flow from operations. Yet at year-end 2013, our market cap was 175% of our SEC PV-10 and currently our market cap is 41% of our SEC PV-10. This disclosure was a stark reminder that there are times when financial and operating performance have little bearing on stock price performance, and this is one of those times.
Now looking at the fourth quarter, revenues, net income and cash flow were above the third quarter and higher than the fourth quarter of last year. Despite late pipes and challenging operating conditions, production guidance was met and consensus estimates were exceeded. Fourth quarter cash flow was $260 million, slightly higher than last year. Full year 2017 cash flow totaled $916 million, a 61% increase from 2016.
Fourth quarter EBITDAX was $309 million and full year 2017 EBITDAX totaled $1.1 billion, 53% higher than last year. Fully diluted cash flow per share for the fourth quarter was $1.06, while full year 2017 cash flow per fully diluted share was $3.73, 24% higher than full year 2016.
As Laith mentioned, please reference the earnings release and supplemental tables on the Range website for full reconciliations of these non-GAAP measures to GAAP.
Cash margin for the fourth quarter at $1.29 per Mcfe was higher than the third quarter and full-year cash margin at $1.24 per Mcfe was 26% better than the full year 2016 figure. We look forward to our remaining pipeline capacity coming online during the first half of 2018, which will help stabilize our margins as basis volatility has reduced.
GAAP net income for the fourth quarter was $220 million and GAAP net income for the full year was $331 million. Adjusting fourth quarter GAAP net income using common analyst methodology, which removes non-cash and non-recurring items, was $55 million or $0.22 per fully diluted share. Adjusted non-GAAP net income for the full year was $143 million or $0.58 per share.
Reviewing significant unit cost structure variances for the fourth quarter, transportation, gathering and processing came in $0.05 per Mcfe favorable to guidance due to in-service (27:56) dates on several new pipelines. The offset to this cost improvement was a $0.07 wider forecast to gas price differential as pipeline takeaway capacity access to better price markets was delayed.
Reflecting the reallocation of capital from North Louisiana to Appalachia, we increased our estimate of expiring North Louisiana acreage, resulting in a $218 million non-cash impairment of unproved properties. Other unit costs were below or in line with guidance.
While not a specific guidance item, I wish to mention that Range, like most all other publicly traded companies, will be adopting the new GAAP accounting standard for revenue recognition in the first quarter of 2018. Under this new accounting standard, costs associated with certain gathering and processing arrangements that are currently netted against revenue will be re-classed to expense.
There is no increase in actual cost with this new accounting standard, only a reclassification between revenue and expense. The result will be an increase in revenue and an identical increase in gathering, transportation and processing expense. I will update guidance to reflect this change and provide a reconciliation between the old and new accounting standards in April.
Over on the balance sheet, as Jeff stated, we have a plan in place to orderly reduce our debt-to-EBITDAX ratio over time, and we intend to bring down leverage ratio faster than our five-year outlook forecast with asset sales. In the meantime, Range continues to have ample liquidity with over $500 million in committed availability under its bank credit facility.
Consistent with our past practice, Range has continued to add to its hedge position during the fourth quarter with over 70% of our anticipated 2018 natural gas production hedged at a forward price of $3.09 per Mcf and over 70% of our projected oil production hedged with a forward price of $53.30 a barrel. Details of our current hedge positions across all of our products may be found in the earnings release, Range website and 10-K.
In summary, the fourth quarter showed steady progress with higher production, cash flow and net income. The full year financial performance for 2017 was markedly better than 2016, with EBITDAX back up over $1 billion and unit cost held in check.
Jeff, back to you.
Operator, let's open it up for Q&A.
Thank you, Mr. Ventura. First question comes from Brad Heffern of RBC Capital Markets. Your line is open.
Hey, good morning, everyone.
Good morning.
I'll start with a philosophical question, I guess. So, as you guys mentioned, you are trading well below PV-10. Why do you think that that is? And what do you think that you can do to address it? I know it's kind of a tough question, but if you could take a shot.
Yeah. Well, let me take a shot at it. It's a good question. I think, one, it – we'll talk about the macro and Range specific. But, one, I think people are typically bearish natural gas right now and if they're into the commodity, probably more on the oil side. Later on, all right, we can do it as a follow-up question if you want, I can address the macro and maybe paint a little bit better picture. But I think the macro is part of that.
I think the other part of it, quite frankly, like we said, are two things. Our leverage is high relative to peers and the results in Terryville have been disappointing, like we said. To address those two things specifically, I think when you look at our leverage, we have a five-year outlook that we put out that I think is a good solid plan led by the Marcellus and I think we really have outstanding high quality rocking team work in the Marcellus to drive that plan.
So to address the leverage specifically, and it's on page 12 of presentation if you look at it, assuming no asset sales and we are actively pursuing asset sales, by 2020, assuming strip pricing, we get debt-to-EBITDAX below 3 times. I think that's important. Importantly, on that same page, we ran a couple of sensitivities. If you assume the strip is correct for gas, but just assume WTI is $60, so currently it's trading over $60 and the strip long-term is a little under that, but if WTI is $60, debt-to-EBITDAX accelerates getting below 3 times from 2020 to 2019. Not that far out. And then, again, to the extent we're successful with our assets sales, we have the opportunity to pull that into 2018. I think that will be a key event for us there in terms of getting valuation back.
And, again, you can, same thing, debt-to-EBITDAX below 2 times on a five-year outlook, 2020, it's 2022. WTI is $60, pulls it to 2021, asset sales would pull that below 2 times to 2020. I think that's important. On that same page, too, with that I talked about debt-to-EBITDAX, but it also increases our free cash flow by 70% or $700 million, as Ray said and, of course, that gives us a great free cash flow yield of greater than 40%, given where we trade.
So I think those are important things. In terms of North Louisiana, we talked about. Partly we're addressing the results there. We're slowing down. We're going down to one rig. We think that's the right thing and we're really redirecting the bulk of our cash flow up into the Marcellus, which we also think is the right thing. So it gives us time to slow down, see where we are in Louisiana. At the same time, we're having phenomenal results in Pennsylvania. Ray talked about some of them. We expect that that will continue.
So it recognizes the great results we have in PA. Also with all that new transportation that's coming on in PA, we expect the prices to come in a little bit, give us better net back in pricing, and through redirecting existing volumes coupled with the focus, the capital there allows us to fulfill our transportation commitments. So we think those are the reasons I think we're trading below – to answer question specifically, those are the things that we're doing specifically to address them.
Okay. Thanks. Appreciate the detailed answer. And then in the prepared comments, you talked about pulling forward value outside of the asset sales that you've talked about in the Mid-Con and in Northeast PA. Is that just more asset sales or are you thinking about other structures like JVs or something along those lines to do that?
Well, it's great question, too. So there's multiple things we're looking at and multiple options in order to help us delever and pull forward value. If you look at the position we have in Southwest PA, we have a big position, we have a big footprint. Importantly, we hold all horizons with any well. So, it's not just the Marcellus, but it's the Utica, the Upper Devonian and within that big footprint. To the extent there's value in some of those horizons or value in inventory that's far out there that we could pull forward that we think is a fair price, we certainly would consider that and do that.
Okay. Thanks.
Sure.
Next question from Holly Stewart from Scotia Howard. Your line is open.
Good morning, gentlemen.
Good morning.
Good morning.
Maybe the first one, either for Jeff or Ray. I'm just curious what specifically are you looking for? I mean, I think you completed roughly 20 wells in North Louisiana in the fourth quarter. So, I guess, what are you looking for as you watch those wells? And then how are you thinking about the changes to the completion design in 2018?
Let me start at a high-level then I'll flip it over to Ray. Again, what we're doing is recognizing the below performance that we've experienced. So, if you go back to 2017, we talked about what the results were for the first-half wells. And although the second-half 2017 wells were significantly better, they're still below what we were targeting.
So last year, we ran four rigs and at times more than four rigs – six or seven rigs, in a spot period, we've cut back. Today, we're at two rigs. In a week, we'll be at one and we'll stay at one rig for the rest of the year. So I think going slower is important.
We've changed leadership. We're incorporating all the knowledge that we have to do that. And at the same time, we're redirecting our capital up to the Marcellus where we've had great results, consistent results. And if anything, it just keeps surprising us to the high side. So we think that's the right way to allocate capital and it's the right pace to go at in Louisiana. But, Ray, you want to hone in on some of the specifics on what we're going to do on the one-rig program?
Sure, sure. It's a great question, Holly. I think what's important to point out and all the things Jeff said, I totally agree with and is exactly why we've moved most of our capital to Appalachia because they've had great success up there and things have improved in longer laterals and capital efficiencies and just all the things we are seeing happen there.
When you look at the last batch of wells that we did, like Jeff said, they're way better than the wells we did in the first half of the year, but they still didn't reach what our expectation was going in. But there were a few wells that did and there were a few isolated cases. I think some wells we announced back – last September that were at the tight curve have continued to perform well. We drilled the best Lower Deep Pink well in the field today and so there's a few things there that we want to do some more testing.
We experimented with some different job sizes, stage spacing, cluster designs, proppant intensity, different things like that that we experimented with over that last batch of wells. And so we literally need to slow down, let the team focus on some technical analysis of all that data, decide what worked, why it worked and what didn't work and why it didn't work, build some models and look at the different areas that we're going to be looking at. But, again, we're going a whole lot slower. It's a lot less capital and, again, pulling in new leadership and a different focus on it going forward.
Okay, great. Maybe could you just expound on the new leadership comment?
Sure. John Applegath, who is leading that division, have retired earlier this year. John did a lot of great things for the company and he was approaching his 70th birthday and was ready to go. And we have promoted Dennis Degner to Senior Vice President. Dennis is going to be overseeing both divisions day to day. Dennis has a lot of great experience as a background and a lot of the efficiencies and the successes we're seeing in the Marcellus are a direct result of Dennis' work up there. So we're going to be still focusing on Appalachia. And like you say, 85% or more of his time is still Appalachia and that's where the lion's share and the engine and our whole five-year plan is based on. But, clearly, we're going to pull in, slow down and put a lot more technical analysis in the North Louisiana assets going forward.
And I'd add to that a little bit. Dennis has done a great job for us running operations for a long time there, now be in-charge of both divisions. Again, still focused on making sure we're doing a great job up in Appalachia as well as trying to pick up what we're doing in Louisiana.
Curt Tipton is going to run our division up in South Point. Curt's been with us a long time, does a fantastic job. I have great confidence in Curt and his ability and the team up there, great depth there. And then Scott Chesebro will replace John Applegath to run the North Louisiana division. Scott has a great track record. He spent a lot of time with Anadarko, actually worked that area and did a lot of the drilling in and around Vernon when Anadarko was running a lot of rigs, and then later on, did a lot of things worldwide for Anadarko. So Scott has a great track record, great resume, and we think under that team, working under Dennis will do great things.
That's great. And maybe just for my last question. Can you just remind us of the total firm pipeline commitments and then kind of when during 2018 you expect to have those filled?
Well, we had three pipeline projects coming on. And when you look at the three pipeline projects, one of them came on in the fourth quarter, one of them literally like January 1. The last of the three is Rover. Rover should be on – we'll defer to Energy Transfer and the comments that they made on when Rover is going to come on. So, it'd be early second quarter, maybe, I think is what they're saying.
When you look at our ability to, again, move existing volumes into the pipeline as well as the new drilling, we think that we'll do a good job of filling that transportation this year and have really over 90% of our natural gas going to good markets. And that's part of – when you look at the Range story, I was talking a lot early on, I quoted a lot of the numbers out of the five-year plan.
The other thing that's I think important to look at on the presentation, and I'm seeing if I can flip through it and find it real quick, I think it may be in the appendix. But we have with our – differentials are for natural gas, for NGLs and for condensate. And again, you see continued improvement in 2018 in all three areas, and a lot of that is a result of the transportation and efficiently using the transportation. The IR team, I'm sure, can give you guidance to what they are, plus it's in the presentation.
That's great. Thanks, guys.
Thank you.
Thank you.
Next question from Adam Meyers from Cowen. Your line is open.
Hey, good morning, guys.
Good morning.
Good morning.
I guess, maybe just starting with the five-year growth outlook here. I'm curious if you could give us any kind of background as to how Range arrived at kind of 11% as the optimal long-term growth rate to hit your leverage targets. I'm talking to some investors, it sounds like some could be wondering why it's not a lower growth rate, potentially throw off some more cash. So, any thoughts you have on that would be interesting.
Yeah. I mean, that's a great question. And when you look at the plan, there were several things we're looking at. Again, it's driven by the Marcellus. It's driven by wells we have high confidence in, in terms of being able to hit the results and targets. I think that the team did a job in terms of when you look at 2018 and 2019, very reasonable assumptions. We really didn't build in efficiencies until you go out to year three, four and five. And the efficiencies we built in were pretty minor. There are things that we see today that are in hand. We assume lateral lengths no longer than 10,000 feet, even though in reality we'll probably do that. So, we think we have a good plan that's well-built and we tied it to strip pricing.
When you look at it, there's a variety of things that you need to look at in order to build the plan. We ran multiple sensitivities. Of course, Holly just asked on the previous question about the transportation we have and filling transportation. So this plan fills transportation, it meets transportation. And when you look at it, it delevers us over time and then throws off a significant amount of free cash flow over time with those rates.
So we're living at or below the cash flow estimates and different pricing estimates. We ran some different sensitivities to show you, again, on page 12, throws off $1.7 billion at $60 WTI and gas strip. That's a 40% free cash flow yield. Those are commitments. It does a lot of good things for us. And of course, we'll continue to look to optimize it with time and to see what the most optimum thing to do is. But it delevers us and then it gives us the optionality with time to either increase dividend or buy back shares.
Right. That makes sense. And then maybe sticking with the five-year plan, deleveraging obviously a key component. Any way that you can give us a sense as to the level of interest you're seeing for some of these non-core assets and maybe just how much an asset sale could accelerate the timeframe for deleveraging?
Like I said, when you do asset sales, it's really important you've got to find the right buyer. I think I'd give examples with various people in the past and good examples for us would be Nora or Bradford County assets. You have to be disciplined and you have to find the right buyer. Again, I'll keep referring to page 12, with no asset sales, debt-to-EBITDAX gets below 3x at 2020. WTI – gas stays at strip and you look at WTI at $60, it accelerates to 2019. If we're successful this year with asset sales, we could pull it into 2018.
Well, okay. Very interesting. Great quarter. Thank you.
Thank you.
Next question from Mike Kelly of Seaport Global. Your line is open.
Hey. Good morning, guys.
Good morning.
You just kind of touched on it, Jeff, but really I want to look at slide 8 that shows kind of your organic deleverage and wanted to get your sense on what you'd like this chart to look like with asset sales, specifically kind of 2020 metrics, where you'd like that to be?
Yeah. When you look at slide 8, again, it shows debt-to-EBITDAX below 3 times in 2020 and below 2 times in 2022. I'd like it to be sub-3 times near term. And a little bit of price improvement, successful asset sales this year, we could get there. So we'll try as hard as we can and focus on that and basically it's pulling the blue bars forward on slide 8 a year, preferably two years.
Got it. Okay. And switching gears. Ray, you hit on the supply/demand dynamics in the Northeast gas market. What kind of stood out to me was that you expect pipeline capacity growth kind of 2x what you see as production growth out of the Basin through the end of – I think it was the end of 2019. I was curious if you could give us a little bit more color on your projections on that supply growth front. You gave like a 6 Bcf a day number and just want to hear a little bit more detail on this – on that analysis that encompasses everybody that's up there, anything you give on that front would be helpful. Thanks.
Yeah. What we did is, of course, it's all internal work. And we looked at third quarter – took the timeframe from the third quarter of 2017 through the end of 2019, which isn't that far away. I mean, it sounds long ways out there, but it's the end of next year. And when you look at that, we've got pretty good line of sight on the pipes (48:30) that are going to happen and I think there's pretty much a lot of confidence in that. Certainly with the current administration and FERC commission, all that looks positive.
So there's about 12 Bs a day when you sum all that up. We simply took basically the consensus estimates and public data of the Southwest Basin producers, both Utica and Marcellus in the areas that would be connected to those pipes. And, again, we're completely holding Northeast PA out. I think that's a totally different animal up there. But if we look at the producers that are connected to those pipes and what they've publicly said and what consensus estimates are built around, it's about a little over 6 to maybe 6.5 Bs a day of growth that everybody is projecting from the third quarter of 2017 through the end of 2019, so with the same time period.
So this is following I think what we've seen historically in this industry over the last almost 40 years I've been doing this is that infrastructure always gets overbuilt. Now the question becomes what happens, and I would also say that 6.2 Bs of gas is at a pretty healthy consensus price of basically over $3. I think it's $3.07 to $3.09 on a consensus basis that people were predicting that kind of growth. With the strip at $2.85, $2.75 or where it's today, it's not there. And clearly that could put that growth level at risk.
So we think, like we said for a long time, that there's going to be ample pipeline takeaway gas capacity in the Basin. It's going to be overbuilt. We think demand pull will start occurring. We already have a lot of that taking place. Even on the liquid side, it's beginning to take place where markets are actually coming to us to buy the gas at the tailgate of the Houston plant, so to speak. So we see a lot of that shift beginning to take place, just like we predicted it would for years. And I think that's kind of how we put all that together internally.
I'd just add to that a little bit. When you look out further into that 2020 or 2020 plus, we really believe based on our internal work that you're going to see sweet spot exhaustion in the Marcellus, Utica as well as in a lot of other plays really all over the county, which is really important when you look at people projecting forward. And then it comes back to who has an inventory that can last. And, again, we think with the quality, the acreage we have and the large number of locations that are in the sweet spot that will put us in a great position. But that's something that I think is not in the market, but it's a real technical factor.
Got it. And just if you had a ballpark number for the amount of volumes that could come from private operators in the region, is that – it might not even be meaningful, but do you a sense of that, too?
I don't think we really have a sense of that.
That's in the data, and it's factored into the analysis.
It's in that number. These are our internal numbers. Within the number, that's included. So it's the public and private people that are collectively incorporated into that.
All right. Appreciate it, guys. Great details.
Thank you.
Our last question comes from David Deckelbaum of KeyBanc. Your line is open.
Good morning, Jeff and everyone. Thanks for taking my questions here.
Good morning.
Just wanted to ask just on the portfolio management process. You all have put together a compelling five-year growth plan, returning capital to shareholders. You've talked about some asset sales. One, I'm wondering, just how now Terryville fits into everything. I understand the process you're going through this year, you'd analyze what you could improve upon. But, I guess, when I think back to when you all made the acquisition in 2016 versus now, it certainly doesn't seem that you need the Terryville in your portfolio relative to the opportunity that you have in the Marcellus.
So, one, I'm trying to get a sense of how long the evaluation process might take and how long you'd like to stick with it before potentially looking to monetize Terryville and kind of attempt to pull some of that value forward. And then, I guess, at the same time, I imagine that this year I wanted to get a sense of how much free cash Terryville is generating in the 2018 plan. And if you would more rather appreciate sort of an underinvested free cash generation coming out of Terryville to sort of supplement a little bit more of the total enterprise over the next couple of years.
Yeah. I mean, in essence, that's what we're doing. We're dialing back Terryville to one rig, so we're basically taking all of our cash flow and some cash flow from there and reinvesting it up into the Marcellus for the reasons that you're saying.
So I think the key is, the results – again, first half results were disappointing in 2017. Second half better, but still not where we want them to be. We've slowed down significantly. We're allocating some of that cash flow up to Pennsylvania to help us achieve great results and fill pipes and do all the things that we're doing there. And then I think the key is what do the results look like as we go through the year. And there's different things to look at and there's different analogies that you could use.
One analogy is Northeast Pennsylvania. Northeast Pennsylvania has good returns and is a strong asset, but, again, where we allocate more capital. Right now, we're allocating to Southwest Pennsylvania. And other good example might be people – if you go back just a couple of years, which isn't that long, and you look at Southwest Pennsylvania specifically, we have the dry, the wet and the super-rich. And I remember we put out economics of those three areas, and the economics at that point in time were the super-rich and the wet were about half the economics of the dry and we got a lot of pressure from people, why in the world would you put any money into the super-rich or the wet, look at the economics in the dry.
And fortunately, we kept putting some money into it and we understood it better. And you look at where we are today and the type curves are significantly better and the team's done a good job. But we'll clearly look at it and we'll look at like we have historically where are our returns, how important are the different pieces to the portfolio and, therefore, what should we do? Do we keep it? Do we allocate capital to it? Do we sell it? I think that's just typically what we've done as we've managed the portfolio over time. We look at real-time data and make what we think is the right decision for capital allocation.
Okay. That's helpful. And, I guess, the only follow-up to that, I guess, is when you look at the split of assets that contribute to free cash generation, you talked about $1 billion or so cumulative in five years. At what point does the Marcellus generate more free cash than Terryville does?
Well, I'll take a stab at it. By virtue of – at the end of that time period, Terryville is declining this year, like we talked about in the outlook and then we're holding it flat 2019 going forward and virtually all the growth is coming out of the Marcellus. So the Marcellus dominates basically starting this year all of those factors. So I think it just becomes smaller and smaller each year as it goes forward and the big lion's share of it's going to be the economics in Southwest Pennsylvania.
Appreciate the responses, everyone.
Thank you.
Thank you. This concludes today's question-and-answer session. I'd like to turn the call back to Mr. Ventura for concluding remarks.
We thank everybody for taking time to join us on the call this morning, and please follow up with the IR team for additional questions that you may have. Thank you.
Thank you for participation in today's conference. You may now disconnect at this time.