Welcome to the Range Resources 4th Quarter and Year End 2018 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 the call over to Mr. Raith 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 Dennis Degner, SVP of Operations and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated presentation that we posted on our website. We'll be referencing some of those slides this morning.
We also filed our 10 ks with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system. Please note that we'll be referencing certain non GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. For additional information, we've posted supplemental tables on our website, to assist in the calculation of EBITDAX, cash margins and other non GAAP measures.
With that, let me turn the call over to Jeff. Thanks, Lee,
and thanks to everyone for joining us on this morning's earnings call. Looking back at the Q4 of 2018, Range continued to make progress on key strategic objectives, generating organic free cash flow, reducing leverage and completing our 2018 drilling program safely and for $31,000,000 less than originally budgeted. Investors have been clear in their request for capital discipline from E and P Companies and most companies' spending plans have moderated as a result. We believe this is the right direction for the industry and it makes sense for many E and P companies given their stage of development. For Range, this is a natural progression as the Marcellus has gone from a concept in 2004 to what is now the largest gas field in the country, if not the world.
That commissioning phase, if you will, can take a long time, particularly if you're trying to capture a sizable acreage position of more than 500,000 acres like Range has in Southwest Pennsylvania. The great thing for Range is that our conditioning phase is now complete. Range's block up acreage position is largely held by production, which allows for increasingly efficient operations as we drill longer laterals, utilize existing pads and effectively source and recycle water. These operational efficiencies are evidenced in our peer leading development costs. Range's transportation and processing capacity is also in place as of year end 2018, which allows us to move products to markets throughout the U.
S. And abroad. This results in a more predictable differentials going forward for both natural gas and NGLs. And with projects like the Shell Cracker and various in basin power projects being contemplated in and around our core operating area, we are seeing demand come to Pennsylvania, which is exciting for Range and for the Commonwealth. In this next phase of development, we expect that returns in free cash flow yields for top tier E and P companies can compete with the broader market and that's certainly what Range will be targeting.
We'll also expect that continued capital discipline from Range and our peers can allow a broader base of investors to recognize those competitive yields and bring their investment dollars back to the sector. But when we talk about capital discipline, it's more than a spreadsheet example of how a company could spend within cash flow in the future at some arbitrary price. We think capital discipline also means sticking to the capital plans that we set at the beginning of the year and communicated to investors. In 2018, the overwhelming majority of E and Ps did not do this as most companies either increased their capital budgets mid year or simply outspent their plans. In some cases, companies did both.
Against that backdrop, I can't say enough how pleased I am with the team's commitment to efficient, safe operations and for not only meeting our capital budget in 2018, but coming in $31,000,000 below our original budget. This commitment to disciplined spending is what you can expect from Range in 2019 beyond. Looking back on 2018, Range's core assets continue to deliver in terms of productivity and efficiency gains, which drove another solid year of reserve additions. Proved reserves increased 18% and drill bit finding costs were only $0.22 per Mcfe. The quality of our resource is further evidenced by a long track record from positive performance revisions.
The positive revisions in 2018 were the result of extending laterals and improvements from optimized targeting and completions as the team continues to do an outstanding job developing our Marcellus resource. The underlying value or PV-ten of Range's reserves was nearly $10,000,000,000 using future strip pricing at year end 2018. After backing out the year end debt balance of $3,800,000,000 this equates to $24 per share, which speaks to the disconnect we currently see in the value of our equity. In addition to SEC proved reserve, which accounts for only the next 5 years of development, Range has approximately 3,300 additional undrilled core Marcellus wells. This provides range of class leading inventory measured in decades that serves our foundation for delivering sustainable free cash flow possible at today's strip prices.
Many of our peers have based their go forward plans on higher prices than are what available today. We agree that commodity prices will ultimately trade above current strip pricing, but we've taken the relatively conservative approach of showing what our assets are capable of at today's prices, which approximates $2.70 per MMBtu for natural gas and $55 for WTI for the next 5 years. As shown in our updated presentation, at current prices, Range is capable of consistently generating free cash from a plan with modest annual growth over the next 5 years. This balanced approach towards capital allocation provides Range and its investors with near term free cash flow and continued improvement in returns, margins and balance sheet strength over the 5 year outlook, generating cumulative organic free cash flow of more than $1,000,000,000 over the next 5 years at today's strict pricing. This equals nearly 40% of today's market cap.
To the extent that we have asset sales or prices improve above these levels, that will simply accelerate the time line for returning capital to shareholders. Unlike some of our peers that have hinted at higher growth at higher prices, Range will remain committed to a balanced approach towards capital allocation as we do not have acreage at the risk of expiring a midstream component, excess transportation agreements or other forces that will drive us to favor outsized growth over free cash flow. Range's ability to deliver sustainable free cash at strip pricing is underpinned by our low corporate base decline and low maintenance capital requirements. Range's base decline entering 2019 was below 20%. This competitive base decline supports a low maintenance capital of only $525,000,000 For $525,000,000 of drilling and completion capital, Range can hold 4th quarter production flat, which is really the starting point for our capital allocation process that Mark and Dennis will cover in more detail.
We believe that slow maintenance capital is a differentiator for Range as additional cash flow beyond that level can be used to bolster the balance sheet, invest in our high return inventory or be returned to shareholders. And given our vast inventory of high quality Marcellus locations, we believe that we're in a unique position to not only deliver on our plan of free cash flow and capital efficient growth over the next 5 years, but we can continue this program far beyond the 5 year outlook into a market that will see other companies exhausting their core inventories. I'll now turn it over to Dennis to discuss operations.
Thank you, Jeff. Production for the Q4 came in at 2,149,000,000 cubic feet equivalent per day. This contributed to an annual 2018 production number that was approximately 10% year over year growth and includes the impacts of both the Mid Continent asset sale and the override interest sale during the year. As previously disclosed, 4th quarter production was materially impacted by an unfortunate incident at Mark West Houston processing facility. Throughout the ensuing outage, Range's Southwest Pennsylvania volumes were curtailed while necessary repairs could be made resulting in an approximate 10 Bcf equivalent reduction in production for the quarter, the majority of which occurred during the month of December.
Repairs to the Mark West facility have since been completed with full operations restored during the 1st week of January. As Jeff mentioned, capital spending for 2018 came in $31,000,000 below our original guidance set at the beginning of last year, resulting in a total spend of $910,000,000 We're proud of the team's dedication to safe efficient operations and capital discipline that led to spending below our planned budget. I'll go into more details on some of the achievements that led to this in a minute, but the broad takeaway is simple. We expect capital spending at or below budget to be the rule, not the exception. As we look forward, our 2019 capital budget is set at $756,000,000 with 90% allocated to the Appalachian Marcellus program and 10% to North Louisiana.
We expect this to generate year over year production growth of approximately 6%, including a 30% liquids contribution while generating in excess of $100,000,000 in free cash flow. We earmarked 93% of the capital to be directed towards drilling, completions, facilities and pipeline infrastructure, which is a slight increase compared to last year's budget and helps to improve capital efficiency per unit of production. The program will consist of 96 wells being turned to sales during the year. In Appalachia, liquids rich wells will comprise of approximately 60% of the expected activity and similar to 2018 up to 50% of the wells turned to sales are expected to be from pad sites with existing production. Average lateral lengths per well are projected to increase this year with turn in lines averaging approximately 10,500 feet, while the average drilled horizontal lengths will increase to over 12,500 feet, a year over year increase of 1600 feet and 2,500 feet respectively.
We see this plan setting us up well for 2020 and in line with the path ahead illustrated in our 5 year outlook. Similar to 2018, our 2019 capital spending is expected to be weighted to the first half of the year with approximately 35% of the capital being spent in the Q1 and sequential production growth projected throughout the year. Honing in on the Q4, the Appalachian team remained operationally focused and turned to sales 16 wells in the liquids acreage taking the 2018 total to 86 Marcellus turn in lights.
Similar to
our last discussion on the prior call, this total is slightly lower than the original number of wells planned to turn in line for the year. The two drivers for this were 7 wells that were completed in the Q4 with first sales pushing into early Q1 along with extending lateral lengths on wells throughout the year. In any given year, we will aim to turn in line the budgeted lateral footage with fewer wells and longer laterals to maximize efficiencies. In North Louisiana, we completed and turned to sales one well during the quarter. In 2018, the North Louisiana team's charge was straightforward, drill our best picks, evaluate the impact of structure and completion design and lastly, deliver on production targets within the capital budget.
Looking back on the year, we've enhanced our understanding of structural influence in the area and have seen benefits from an increased completion design. When evaluating the wells from last year, the average production is in line with our expectations, but not where they need to be on a competitive returns basis. The early part of 2019 will be key as the team tests the latest structural aspects for the Cotton Valley and will assist in determining the assets overall direction going forward. Now let's look back on some of the team achievements for the year that drove our capital underspend. A key theme for Range in 2018 was our ability to drill long laterals in the Marcellus resulting in a lower cost per foot.
The Southwest Pennsylvania team was able to increase the average lateral length drilled by 8% in 2018, while drilling the longest Marcellus well at 18,600 feet, along with drilling 3 more of the basin's top longest laterals to date. In addition to drilling our longest laterals, we also saw our drilling efficiencies continue to improve. The drilling team was able to increase footage drilled per rig by 20% versus 2017. And with these efficiency gains, along with 18 wells successfully drilled beyond 15,000 feet, the team has been able to reduce the drilling cost per foot during extended lateral operations by as much as 30%, a key component when looking at our capital underspend and in improving our overall capital efficiency. Water recycling also continues to play a significant role in our program and 2018 was no exception.
By recycling 100 percent of Range's water in Southwest PA, the team played a large role in achieving our corporate LOE of $0.17 per Mcfe for the year. And by taking 3rd party water, they reduced the per stage water cost by 10%, resulting in one of the largest drivers in our capital underspend. These are just two examples of where the team's creative efforts combined with our high quality asset and contiguous acreage position have strongly impacted the program efficiency. On the marketing side, 4th quarter marked the 1st full quarter where Range had access to all of its contracted natural gas transportation as Energy Transfer's Rover project provided additional outlets to the Midwest and Gulf Coast in September. The quarter also saw the commissioning of Mark West's Harmon Creek 1 processing plant which reached full capacity in early December.
As we discussed on the prior call, 4th quarter wells were focused in our liquids rich acreage near this new processing plant, allowing us to maximize utilization of this newly available infrastructure. The 4th quarter natural gas differential of $0.08 under NYMEX was the best Q4 differential Range has seen since 2012 due in large part to the addition of transportation out of Appalachia. Going back a few years to the 2013 to 2014 timeframe, the Appalachia Basin took on significant commitments to have natural gas transport built to the Midwest, Gulf Coast and Southeast, enabling the current market environment of improved basis. It seems to have been a long time coming with various pipeline delays, but overall it ended up aligning perfectly with Range's revised production profile. Compared to our original 2014 plans, we reduced our production trajectory and corresponding capital spend, but we're able to fully utilize each firm transport project shortly after its in service date.
Range's early strategy of creating a diversified market portfolio inclusive of in basin exposure has been and is expected to continue to be beneficial to realize natural gas pricing and managing cost structure. To that end, going forward, Range expects to keep its natural gas transportation full and sell incremental gas production in the local markets, which have improved as infrastructure has been built out in the Southwest part of Appalachia. On the liquid side of marketing, as the only producer with propane capacity on Sunoco's Mariner East 1, Range has been able to capture premiums to the Mont Belvieu index price by exporting the majority of its propane to international markets since early 2016. In addition, the company sent the majority of its normal butane and remaining propane volumes during the summer to Marcus Hook for export via local rail. The majority of those same volumes are being sold locally during the winter months.
In total, Range markets over 70% of its corporate NGL production each quarter. As we continue to develop our liquids acreage, these additional outlets for NGL production are beneficial in providing stability to NGL price, especially during the summer when in basin demand is low. Given the added purity volumes that could be supplied to Mont Belvieu over the coming years, we believe additional exposure to international NGL prices are warranted. As a result, Range has taken capacity on Mariner East 2 for a combined 20,000 barrels per day of propane and butane starting in April 2020. Importantly, we have the ability to fill that capacity with propane and butane volumes we produce today, leaving flexibility to sell incremental NGLs in basin on a go forward basis.
In January, we lost access to capacity on the Mariner East 1 pipeline following the appearance of a subsidence along the pipeline route. As a result of the outage, we are utilizing available capacity on Mariner East 2 to continue moving propane to the Marcus Hook terminal. For ethane, we have multiple options for marketing production, including the ability to sell ethane as natural gas. While not materially altering corporate cash flows, the delayed restart of Mark West plants and the Barner East outage have reduced production volumes and as a result Range's 1st quarter guidance of 2,225,000,000 cubic feet equivalent per day reflect the estimated production impact. Before handing over to Mark, I'll close out with this.
We're extremely proud of the team's accomplishments in 20 18 and are excited about what's in store for 2019 as we continue to deliver on the capital budget and our production targets while we drill and produce our most cost effective and operationally efficient wells. I'll now turn it over to Mark to discuss the financials. Mark?
Thank you, Dennis.
Results for the Q4 and full year 2018 demonstrated the quality of Range's assets, the efficiency of our operations and the company's commitment to budget and capital discipline. Driven by the strong operational results Dennis just described, Range was able to achieve full year cash flow from operations of $991,000,000 a $174,000,000 year over year increase driven by cost controls, improving prices and rising production. The $991,000,000 in 2018 cash flow compares to $910,000,000 of capital spending, which was $31,000,000 below budget. The transition to free cash flow mid year 2018, combined with the execution on asset sales allowed Range to reduce absolute debt and reduce leverage from 3.7 times at year end 2017 to 3.1 times at year end 2018. Again, I would like to point out 2 key accomplishments for Range in 2018 that sets us apart from our peers.
First, we began generating free cash flow and second, we came in under budget. 2018 results also include non cash impairment charges taken against goodwill and unproved properties. These charges are a result of our strategic focus on the highest return projects and rightsizing our capital program to generate free cash flow. As described fully in the 10 ks, non cash impairments taken in the 4th quarter were $1,600,000,000 for goodwill and $436,000,000 for certain North Louisiana unproved properties. The decline in range of stock price late last year triggered a quantitative assessment under GAAP rules and that evaluation concluded that goodwill was impaired.
The 4th quarter impairment of unproved property related to value originally allocated to the extension area outside Perryville in North Louisiana. As part of our stringent capital allocation process, we determined we no longer had the intent to develop these properties. The competition for capital within range is substantial and these potential drilling locations were dropped as a result of strong returns elsewhere in the portfolio. As we look forward to 2019 and beyond, the framework through which we allocate capital is paramount in understanding the near and long term value the Range business can generate. As described last year, borne out in our results and reiterated today, our focus is on creating economic value.
We begin by estimating cash flow at strip pricing, assess maintenance CapEx and then consider the economic reinvestment of cash flow, be it drilling, debt reduction or returns of capital to shareholders. Evaluating reinvestment options includes weighing each plan's potential impact on total free cash flow, absolute debt reduction, leverage ratios, capital efficiency, unit costs, margins and the change in base decline rate. For 2019, Range developed a plan focused on balancing the goals of generating meaningful free cash flow at strip pricing, reducing absolute debt, maintaining capital efficiency, managing leverage and efficiently utilizing existing infrastructure. In balancing these objectives to maximize the value from the 2019 capital program, we developed a $756,000,000 capital plan that is focused and efficient with approximately 90% of the capital going towards the Marcellus. This 2019 budget is 20% or $185,000,000 lower than the 2018 budget, generates free cash flow well over $100,000,000 of current store pricing, reduces debt, maintains capital efficiency, enhances margins and results in an estimated 6% production growth.
At strip pricing, Range estimates free cash flow in 2019 that equates to a yield of a 4% at current share prices. After including expected changes in working capital, Range estimates the 2019 free cash flow yield approaching 7%. This outcome demonstrates our commitment to strategic principles combined with the efficiency of our operations and the quality of our assets. While the 2019 plan allows us to reduce outstanding debt, we remain focused on asset sales to accelerate balance sheet improvement. To reiterate our philosophy on capital structure, we believe that a balance sheet with less than 2 times leverage is the optimal position for our business.
As we progress towards that target, we become more willing and able to return capital to shareholders with the intention of announcing durable programs such as share buybacks or increased dividends. We would expect these programs to also be opportunistic when we see substantial disconnects between the intrinsic value of Range's assets and its stock price, such as what we see today. In summary, we remain focused on converting consistently efficient operations on top tier acreage into tangible shareholder returns through the application of a disciplined capital allocation framework. We believe our 2019 plan demonstrates that focus, highlights our asset quality and proves the ability and commitment to delivering sustained and meaningful free cash flow.
Jeff, back to you.
Operator, let's open it up for Q and A.
Thank you, Mr. Ventura. The question and answer session will now begin. We will take as many questions as time permits until the end of the call at 10 o'clock am Eastern Time. Our first question comes from the line of Holly Stewart with Scotia Howard Weil.
Good morning, gentlemen. Maybe, Jeff, we could just start off by talking about kind of the overall M and A landscape out there, whether it's in the Appalachian Basin or elsewhere, just thinking about your pursuit to continue selling assets?
Well, I think so you're talking about asset sales, not corporate M and A. Is that the question? Correct. Yes. Just clarifying.
Yes, I think in this market, the key is it's a tough market to sell assets. But I think to the extent you have a quality asset that people are looking for, it's possible. As evidenced by our 1% royalty sale last year, we thought we got fair price or a good price for. So I think it comes down in this market. If you've got the right assets and you're patient, of course, and we'll be as not that we're very patient, we'll be as aggressive as we can to get them done.
But so I think we have the opportunity. I think we've laid out a great plan that has that balances moderate growth with good free cash flow yield and it's free cash flow positive now and at strip pricing. We don't have to rely on a higher deck, but to the extent we can get assets sold, I'm sure we'd like to do that to accelerate our plan and pull value forward.
Okay. Great. And maybe, Mark, if you could just touch on I know you talked about the optimal kind of below 2x leverage targets out there. But if you could just touch on maybe what you'd like to see sort of near term before deploying capital back to shareholders?
Sure. I think the guidelines we laid out last year still hold. Our immediate goal is below 3x. And I think as you approach 2.5x, the likelihood, the size and the frequency of a return of capital increases. The interest in our ability to do that increases substantially.
And then certainly, as you approach 2x and below 2x our long term target, that becomes, I think, a recurring core element of the strategy. So it's opportunistic and scaled appropriately as we approach that long term target. But as you execute asset sales, accelerate the balance sheet improvement and again approach that 2.5 times, I think that becomes a more meaningful element of our strategy in the conversation amongst the management and Board members.
All right. That's helpful. Thanks, guys.
Thank you.
Your next question comes from the line of Arun Jayaram with JPMorgan.
Yes. Good morning. I was wondering if
you could help us understand on the Mariner East one outage, just maybe the operating and financial impact in 1Q and 2Q and thoughts on when capacity would be restored?
Yes, this is Dennis. At this point, it's still a little unclear on when the operations will be restored on that particular line. We remain in close contact, as you would imagine, with the folks at Energy Transfer around the operational status of that line. The good news is, is we have optionality. We have other outlets that we use on a regular basis to basically transport our ethane to other markets.
We continue to look at those options through the Q1 to both capitalize on pricing environments, but also minimize the impact when it makes most sense. So we'll continue to do that through the Q1. From a financial and production aspect, I don't think we have is something that we're prepared to share at this particular point other than the guidance that we've shared here in the call today. We feel like we're on track with the 22%, 25% It also puts us in line with our growth profile of 6% for the year.
Okay. And just the cost of the capacity, you have some capacity on Mariner East 2. Could you maybe discuss that cost?
That's the kind of detail that we've not typically provided, whether it's Apex or AmeriEast 1 or Meriden West. But Alan, perhaps you can talk about the strategy behind taking into capacity.
Sure. And I'll point out there's published tariff rates on the pipeline, so it's available on the Internet. People can look that up. With the details of our own deal, as Lake was just saying, are confidential. Overall though, the reasons for taking on ME2 capacity, the Northeast market is a it's a great market.
It's very seasonal. It has wonderful winter demand, but unfortunately in the summertime, there is not a preponderance of local demand. And to make it a little bit more challenging, actually, there's not much storage in the local area. So kind of like our strategy in natural gas, as we're marketing our products directly, we like to build up as much optionality in our portfolio as we can, so that we can get to diverse customers and industries for our product and realize the best overall prices. So what we've taken out actually is 20,000 barrels per day on ME2 starting next year.
And we'll actually be able to fill that volume with existing capacity. And we'll have optionality on the remainder of our capacity to continue to sell to local markets or actually to put it on walk up space, let's say, on ME2. So the ME2 capacity, again, as we see it, it provides a good option for the summer markets and actually provides a price for it to winter markets. It's all the way around. It's a good thing to have.
And then it's very much thought.
Arun, I might add that the cost of ME2 is embedded in the cost guidance that we provided in the 5 year outlook where you see the step down from 4Q 2018 to 4Q 2019 and then a further step down in the 5 year outlook. And it's also embedded in the pricing guidance that we provided, which shows about 40% of that ETI in the years 2020 through 2023.
Great. And my final question, what are the next steps here for Terryville as you evaluate this asset? And I was wondering if you could help us with the breakdown. I think you have a $600,000,000 PDP valuation. If you could help break that out between Appalachia and North Louisiana, it would be helpful.
So I'll refer you to the 10 ks and the reserve reports in the back to give you the valuations. As it relates to the plans for North Louisiana, I think the starting point there is to look at our capital allocation for the 2019 plan. And with 90 plus percent of the capital directed at Marcellus, we are focused on risk adjusted returns and maximizing the returns and the value of that capital. That being said, some element of capital is allocated to North Louisiana. The allocation of that capital is to optimize and preserve the value of the asset and the cash flow and to explore that here early this year.
And we will continue to evaluate and allocate capital, again, based on that framework I described during the scripted portion. And the allocation of capital to the division is designed to optimize the value and the cash flow, as I said, no matter the path forward for that asset.
Great. Thanks a lot, gents.
Your next question comes from the line of Brian Singer with Goldman Sachs.
Thank you. Good morning. On Slide 11, what's the major drivers of the unit cost reductions as you invest more capital and grow more in your maintenance versus balance versus full reinvestment scenarios, how much of this is just moving from underutilization to full utilization of transportation contracts versus potentially selling more into the local market that would result in lower transport costs or maybe there are other drivers
of that? Thank you.
Sure, Brian. That's a good question. I'll actually direct you to Slide 12, where we lay out the components of unit costs.
And you can see just the order of
magnitude and where the savings are coming from. So as we look at the trend in costs from Q4 2018 out over the course of the 5 year outlook, we estimate roughly $0.30 in NCFE savings. It's driven in large part by savings on gathering, processing and transport. If you think about the components of gathering, processing and transport, a significant element there is the long haul transport that as of year end was fully utilized. As we go forward, as Dennis described earlier, we would expect and intend to sell in basin for incremental volumes.
So simplistically, you're spreading that existing cost over a larger volume in base, and you have the ability to continue fully utilizing that and drive down that on a per unit basis. I would also point out that given the early start or the kickoff of the Marcellus with our early contracts, you begin to have smaller contracts come up on maturity, and we have the option to allow some of those to expire. So there's optionality embedded there to optimize the portfolio over time, should that be the most economic outcome. We also have some processing capacity that rolls off as early as next year. So there are multiple elements in terms and multiple paths relative to some modest growth driving that down over a 5 year outlook or just optimizing the contracts depending on what our ultimate path forward is.
You also see savings driven pretty much across the board. Some savings are possible through a little bit on the LOE front. You also have savings in interest expense as we pay down debt. And then, of course, there's some savings in driving down G and A on a
per unit basis as well.
Got it. So I guess in comparing that 4Q 'twenty three column on Slide 12, as you referred to relative to the scenario analysis for the full year 2023 on Slide 11, it's really more of the transportation and the ability for scale to the higher production scenarios to lower the G and A per Mcfe?
In the scenario that we have laid out here as an example, yes, it is predominantly the gathering, processing and transport. But if you were under a different scenario, again, you have the optionality around managing those contracts that are coming up on maturity. So there are multiple paths to achieving that same objective.
Great. Thank you. And then my follow-up is with regards to CapEx in 2019. Can you just talk about the trajectory that you see across the quarters? Thank you.
Yes, Brian, this is Dennis. When you look at we talked about earlier in the call, Q1 is going to be front end loaded while the year will be with Q1 being around 35%, could be just a little bit less than that actually, but close to 35% for the quarter. Then you'll see us start to have a little bit of a tail off, within good consistent activity for the rest of the year. It's going to be very similar to 2018. It's an approach that we've taken over the past few years actually, but it also aligns us with the growth that we're talking about in our 5 year outlook for 2020 toward the end of the year.
Great. Thank you.
Your next question comes from the line of Ron Mills with Johnson Rice.
Good morning, guys. How are
you all this morning? Good morning. Good morning.
Good. I was calling just a quick question. If you talk about, I guess, it's Slide 11, where you talk about the balanced approach in a 2.70 gas environment and the impact it can have on leverage just by delivering the same free cash flow. I know the company is trying to get away from talking about growth, but when you think about growing free cash flow on an annual basis, is this something where you think kind of the mid to upper single digits growth is a pretty likely output given that balanced approach to free cash flow and growth?
Thanks, Ron. That's a good question. And I think you obviously see some differences in how we laid out the 5 year outlook this year as opposed to last year. Last year, we gave a specific example of a case that had a stated growth number in it. It was an example.
But what we were intending to do this year was focus more on the framework and how we were allocating capital and the thought process behind it and how we go about balancing the different and sometimes competing objectives or metrics in measuring success. And that's what you've got here. So the case we've laid out and at the price deck currently out there that generated our 2019 plan that resulted in 6% year over year production growth but was predicated on the free cash flow and the free cash flow yield achievable, you do end up at mid single digit type production as a fallout of that thought process. So to your point, some element of growth does present advantages and improve certain metrics. It improves your unit costs.
It does allow you to maintain and grow cumulative free cash flow, which is the focus and the primary input to the process. So at a point in time, at this price deck, I would say, yes, the mid single digits type production growth number would be the fallout. But that's not to say that's the dedicated path. If prices are lower, we would scale back that reinvestment rate to preserve free cash flow, and the gross number would fall out at something less than that. And if prices are higher, what I would point out is that there is no acceleration in production growth or reinvestment in drilling activity.
It's an increase in free cash flow.
Okay, great. And then as it just relates to particularly on the ethane side, you talked about either selling into local markets in the meantime and or keeping in the gas stream. Can you just remind us of your contracts in terms of pipeline quality? Are you at a point or do your contracts allow you where you can keep the gas in the stream and still stay within standards?
Yes. Good question, Ron. With the volume that's impacted on ME1, we don't see any issues with pipeline quality spec before to reject that volume. So if that's the question, there really isn't any issue with that. And typically what we're looking at is just the overall value of the broader portfolio of recovering the ethane or leaving it in the gas stream.
Okay. And then from the guidance in terms of the way you talked about guidance, is that assuming you move to rejection or you stay in recovery mode?
Yes, Ron. We've kind of done both. When you look back over the course of Q3 as a good litmus test, when we saw an opportunity to take advantage of some better pricing, we certainly will look to do so. When we have other drivers, maybe whether it's an upset condition or maybe a swing in pricing in other direction, we may actually look to reject into the natural gas stream. Because we essentially don't move to max extraction as a part of our base plan for a year over year basis, we have that optionality, which we really like as we look at our plan on an annual basis.
Great. That's it for me. Thank you.
Your next question comes from the line of Paul Grigel with Macquarie.
Hi, good morning. Could you please provide an update on
the EVP process? Is that still a
hire that is being contemplated by Reach?
Yes. Let me give you an update on that. And to do that, let me back up a little bit. As we announced last summer jointly with Selling Stone, we agreed to have 4 directors go off the Range Board and 2 directors come on. As of right now, 3 of those 4 directors have stepped off the Board And we added Steve Gray as one of the 2 new directors, and Steve has been a great addition to our Board.
He was the former CEO of RSP. So we're still in the process of filling the other slot and working closely with SailingStone to make sure we get another high quality director like Steve. The Board has decided to wait until we get the final Board in place and then let a little time pass and then let that newly revised Board decide whether we need that slot or not.
Okay, great. Thank you. And then could you elaborate on the directional change in the decline rate over time on the 5 year plan? And as a corollary, are there any constraints on the system that are balancing out some of the overall corporate decline? Yes.
Paul, this is Alan. The overall decline is, I think, very, very consistent with what we have provided historically to you. We said in about 5 years or so historically that we'd be down 10%. This is
very similar to that.
One of the things you saw last year was low 20s initial decline, and that was because of the very large ramp in activity in the Q4 of 2017 that caused that ramp. I think historically, just quality of the assets. Is there some constraints? Yes, there are. But it's not really material to the overall decline.
It's really quality of the assets. And I think the other
thing you're also seeing is the
benefits of continued longer laterals and a lower decline rate from those wells because of the systems
that they're flowing
into. But historically, it's very, very consistent with what we've seen other than just the 1st year, which is just a function of activity in the Q4 of the previous year.
And I think that's the key part of the Range story is a low corporate decline rate. Below 20%, I would argue is if it isn't at the head of the class, it's near the head of the class for even all the Appalachian gas producers, let alone Permian producers and oil producers that will have base declines that are maybe almost double that. So that low corporate decline really leads to low maintenance capital, which allows us to be free cash flow positive and generate good fleet free cash flow yield now, where several of our competitors are still negative free cash flow and so on. So I think that puts us in a great position, quality rock, low base decline.
Certainly a critical driver. Thanks so much.
Thank you.
Your next question comes from the line of Bob Brackett with Bernstein.
Hi, guys. I had
a question around lateral length. I noticed in the 5 year outlook economics, you took the lateral length from 11,500 to 10,000 everything scaled with that. Can you talk about was that done to make the math easy for us or is there something going on there? And where do you see your typical lateral lengths kind of this year and in the 5 year plan? Yes, Bob, this is Dennis.
As we look at the plan ahead for 2019, the drill plan for us is to average across both divisions 12,500 feet. Really when you look at Appalachia though, that number as you would imagine is going to be a little bit higher than that, just given some of the track record and also records that we've announced just here at the 18,600 foot lateral. Really, this is upside in the numbers. As you look at how we're communicating the 5 year outlook and what we are saying is the plan going forward in our financials versus what we're executing. We're always going to strive to extend lateral lengths where it makes sense and where we are able to do so in the field.
So you should expect just like in prior years, our ability to extend laterals as we continue to improve the efficiency
of our asset.
Okay. And so that should just increase over the 5 year plus. So I shouldn't use that reduction in the back to mean anything except that's an easy way to do the math?
That's correct.
Great. Thanks.
Your next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt.
Hi, good morning. Some of your peers have been moving towards wider spacing in the Marcellus and Slide 22 of the presentation seems to indicate you're working on some of the same concepts. Can you provide some color on your 2019 spacing design versus what's baked into your inventory count?
Yes, Sameer, as we look at our acreage position and the spacing, we like the plan that we have. And as you look across the field, you're going to see our range be anywhere from 750 to 1000 foot inner well spacing. We like how that lines up when you look at the well performance and the 1,000 wells that we've studied over the past several years. But as you would imagine, when you go to the eastern side of Washington County, you've got everything from dry gas to the western side of Washington County where you have 13 50 type BTU type gas structure. That means the rock could be different.
So we continue to test and look at what is the most optimum path for us and plan. But when you look at the prior historical well results and how we've also had positive revisions of type curves over the course of time, We like the position that we're in when you look at our inner well spacing.
I would just add to that a little bit. When you look at our wells on a per 1,000 recovery per 1,000 foot of any of the operators in the Southwest part of the play, they're the highest. Look at our cost per 1,000 foot in the Southwest part of the play. Really in the whole trend, they're the lowest. So that's a great combination where we are.
But there may be upside and certainly, we'll that could be good upside that comes with time.
Okay. That's helpful. And then I also just wanted to clarify some of your earlier thoughts regarding Terryville. It sounds like while you're still allocating capital today, there's a keep versus sell decision coming in the back half of this year. Is that the right way to interpret your comments?
This is Mark. I would just say that, 1st and foremost, our commitment is to creating value. And Range has a long track record of evaluating rates of return on all assets. And that approach to evaluating assets that can compete for capital has led to a long history of high grading the portfolio. So as it stands today, we believe allocating a very modest element of the capital budget to North Louisiana preserves the value and optimizes cash flow, again, no matter the path forward.
So I'll just leave it aside.
Okay. Thank you.
Your next question comes from the line of Rehan Rashid with B. Riley FBR.
Good morning. Just one or two quick questions. 1 on the balance sheet, the next big tranche due is not till 2021, right, $500,000,000 and then almost $1,000,000,000 in 'twenty two. When do you start planning for how to kind of address that those maturities? That's 1.
And 2, unrelated question, but on the overriding royalty sale, what context, what setup would you have to see to do another 1 or 2, those that type of a transaction?
Sure, Rehan. First, starting with the balance sheet, you're right. It's June 2021 is the first bond maturity. We are in good shape in that we have a fair amount of time to enable us to be proactive in dealing with those maturities. So the liquidity under the revolver is ample.
And as we execute, hopefully, on asset sales, that frees up additional optionality and choices to refinance those bonds. We can also be proactive in accessing the high yield market and turning those out. So you can expect us to deal with those maturities well ahead of time as things unfold frankly, over the course of this year. As it relates to the override, that investor demand for yield oriented instruments is high, especially when you can get a high quality asset that also has a growth component to it, a potentially modest growth component. So there was more interest in that override when we executed and closed on that sale October of last year.
So we believe that there is more depth there in that market. We were in a good starting point with Range's high net revenue interest. We had an 83% NRI prior to that 1% sale. So at 82%, we're still well above the average of producers in the area. So we would be willing to consider an additional 1% to 2% at the right valuation.
We see that as potentially yielding good cash flow upfront, realizing and crystallizing good value for shareholders, while also repositioning the balance sheet. Just one quick follow-up on that. I mean, how would that stack up against, let's just say, a sale of the kind of Louisiana assets? Are these independent decisions? Or if one gets you to a leverage point, you'll be happy enough with what you'll be happy you won't do something like this overriding oil piece sale?
The A and D market is very unpredictable about finding a meeting of the minds between buyers and sellers. So as we proceed much as we did last year on divestitures, we proceed down multiple paths at the same time to try to increase the probability of getting a fair transaction completed in a timely fashion. So I wouldn't say that they are dependent on each other, each of the asset sale packages, be it acreage, be it an override, be it Northeast PA or ultimately other assets in the portfolio. So we are moving down multiple paths at the same time. Thank you.
Thank you.
We are nearing the end of today's conference. We will go to Brad Heffern of RBC Capital Markets for our final
everyone. A couple on the guidance. So looking at the CapEx, it looks like the well count year over year is pretty similar. The lateral lengths are longer. It doesn't look like the well costs have changed that much, but the CapEx is down 20%.
So I was hoping you could reconcile that. And then additionally, the 30% liquids guidance seemed a little low to me. I mean, in the Q4, it was 31%, and I assume that that was artificially reduced by the Houston plant downtime. So, any color on that as well? Thanks.
Brad, I'll start with really the activity. I mean, when you look at the turn in lines and you look at the drilling activity, really the story for 2018 as we talked about was drilling efficiencies and long laterals. You'll continue to see that from our side as the activity progresses through 2019. So as you look at rig counts and number of wells, it may not always be in some ways the best proxy for what kind of activity and also inventory we would carry into 2020 to stay in line with our 5 year outlook. So we feel good about how all that's coming together.
From a liquid standpoint, really we see some flexibility when you think about, again, as we talked about extraction versus rejection into the natural gas stream, well mix. So as we start off maybe at any point or any given quarter, we may see well mix influence also that liquids contribution. We've got some exciting dry gas wells that we've recently brought online that we'll talk about in the next quarter call. All of that influences that liquids percentage. But as you look at the percentage we shared earlier in the call notes, essentially it's going to be a heavy focus for us in our processable gas window to utilize that infrastructure that we've committed to over the past few years.
Question and answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks.
Yes. Thanks everyone for taking time to listen to our story this morning. We appreciate that. If you have additional questions, please follow-up with our IR team. Thank you.
Thank you for your participation in today's conference. You may disconnect at this time.