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Range Resources (NYSE:RRC)
Q4 2019 Earnings Call
Feb 28, 2020, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Welcome to Range Resources' fourth-quarter and year-end 2019 earnings conference call. [Operator instructions] Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question-and-answer period.

At this time, I would like to turn the call over to Mr. Laith Sando, vice president, investor relations at Range Resources. Please go ahead, sir.

Laith Sando -- Vice President, Investor Relations

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, chief operating officer; and Mark Scucchi, chief financial officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website.

We also filed our 10-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. 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.

Jeff Ventura -- Chief Executive Officer

Thanks, Laith, and thanks, everyone, for joining us on this morning's call. Looking back at 2019, Range made steady progress on key strategic objectives, improving our cost structure, executing multiple accretive asset sales, reducing debt, bolstering liquidity and completing our 2019 drilling program safely and under our original budget. Looking at unit costs first, Range was able to reduce cash unit costs by 12% over the course of 2019. Mark will touch on the improvements in more detail, but it's important to point out that these unit cost reductions drive lasting enhancements to margins and cash flow that don't require a change in commodity price.

While we made significant improvements across the board in 2019 on GP&T, LOE, G&A and interest expense, we remain focused on becoming even more efficient in the years ahead. Operationally, the team continues to innovate and reduce normalized well costs. As a result of thoughtful planning, efficient operations and a laser focus on capital discipline, the team was able to deliver the 2019 operational plan for $28 million less than originally budgeted. This is the second consecutive year Range has achieved these types of savings, spending less than budgeted, which is a reflection of our commitment to disciplined capital spending.

Range has been a leader in well cost per foot among Appalachian producers since discovering the Marcellus. As Dennis will discuss, the operational plan that we've laid out for 2020 shows that we're continuing to find ways to become even more efficient with our well costs approaching $600 per lateral foot, which is the best among our peers. Range's class-leading D&C costs, coupled with our shallow base decline and our substantial core inventory, all come together to support a very low and sustainable maintenance capital. Range's base decline entering 2020 was approximately 20%, allowing for maintenance capital of approximately $500 million.

Importantly, this maintenance capital figure is sustainable as the lateral footage Range is drilling, completing and turning in line for the year is all very similar, leaving us well-positioned to continue into 2021 and beyond with equal or better capital efficiencies. This is unlike what we've seen from many others in the industry, who are relying on significant DUC drawdowns for massive outspends in the last couple of years to provide a short-lived tailwind into 2020. Rather, our $525 million all-in capital to produce 2.3 Bcfe per day is sustainable going forward and is a positive differentiator for Range. We announced this year's $520 million capital program last month, which is aimed at aligning spending with cash flow.

Prices have come down since then, but we are fortunate in that we have flexibility to adjust our program as we are efficiently utilizing our existing infrastructure and have cushion over and above our various commitments. In every year's budgeting cycle, we're looking at multiple scenarios as we seek to optimize our operational plans and financial outcomes. This year is no different. And if we don't see an improving macro, we will adjust our capital accordingly as aligning spending with cash flow remains a priority.

As I just previously highlighted, Range is coming below budget for the last two years. We've countered our shallow base decline, low well costs and maintenance capital requirements for years. Importantly, these positive differentiators bear out in the reported results. Taking a simple look at the relative capital efficiency using actual D&C capital spend per unit of production, Range led all Appalachian producers in 2019, and we expect similar results going forward.

As others exhaust their core inventories in the years ahead, Range remains well-positioned with multiple decades of inventory, providing us a solid base for delivering free cash flow over time. Looking back at the last 18 months, Range also made significant progress bolstering our financial position. Not only have we improved our cost structure, streamlined our operations and continued to add hedges, our capital spending has been at a near cash flow from operations, allowing us to reduce absolute debt by approximately $1 billion through asset sales. In the fourth quarter of 2019, we also increased the commitments on our credit facility from $2 billion to $2.4 billion, further enhancing liquidity.

When paired with the refinancing of $550 million of debt in January, Range has materially derisked its go-forward plans. We remain active in our efforts to monetize additional assets and remain focused on positioning the company for success through the cycles. The asset sales that Range accomplished in 2019 not only improved our financial position but also reflect the significant value that Range has in its asset base, value that we believe is not reflected in the equity market today. This substantial store of value is also reflected in Range's proved reserves at year-end 2019.

At year-end 2019, the PV-10 of Range's proved reserves was $7.6 billion. For context, after backing out our current debt balances, this equates to over $17 per share. In addition to proved reserves, which only accounts for the next five years of development, Range also has thousands of additional core Marcellus wells that provide Range a class-leading inventory and future runway. As inventory life and core exhaustion become growing narratives for the shale industry, Range's depth of core inventory is an important differentiator and competitive advantage in comparison to both Appalachian peers, as well as operators in other basins.

Before turning it over to Mark and Dennis, I'll reiterate that I think Range has made great progress over the last 18 months in the face of a difficult commodity environment. We lowered our unit costs significantly. We delivered our operational plans at less than originally budgeted for the second year in a row. We continued to lead in well costs and capital efficiencies, and we significantly derisked our go-forward plans, paying down over $1 billion in debt and refinancing our nearest-term maturities.

Over to you, Dennis.

Dennis Degner -- Chief Operating Officer

Thanks, Jeff. Capital spending for the fourth quarter came in at approximately $152 million with our capital spend for the year totaling $728 million. This includes $667 million for drilling and completions, $57 million on acreage and $4 million for gathering and other support activity. Our actual spend was $28 million below our capital plans set at the beginning of 2019 and is a direct result of the operational and technical and build upon Range's operational efficiencies, implement innovative technologies, such as an electric fracturing fleet, and reduce service costs in the current environment.

Similar to our message one year ago, the initiatives that underpinned our capital underspend in 2019 are primarily attributed to the continued success of our water recycling program, improved drilling and completion efficiencies and service cost reductions. I'll go into more detail on these items in just a few minutes. Last year, our message was clear. We expect capital spending at or below budget to be the rule, not the exception, and the team delivered yet again.

Production for the fourth quarter came in above 2.34 Bcf equivalent per day, putting us firmly at the upper end of our Q4 production guide. This generated annual production of approximately 2.28 Bcf equivalent per day, 4% higher than 2018. Our annual production was comprised of 30% liquids and includes the production impact of asset sales executed during the year. Continued excellent field run time of our operations and strong well performance from both new and existing wells across Southwest PA helped us deliver on our production plan to round out the year.

As we look forward into 2020, our capital budget has been set at $520 million with our activity focused on the Appalachia-Marcellus program. We have earmarked 94% of the capital to be directed toward drilling- and completions-related activity, which is in line with last year's budget. The program will consist of 72 wells being turned to sales during the year, while capital allocation will result in approximately 50% of our turn-in-lines to be located in our dry gas acreage with the remaining 50% being split across our liquids-rich position. Similar to prior years, approximately half of the wells planned to turn to sales this year will be from pads with existing production.

Moving back to pads with existing production has become a routine part of our program year in and year out, allowing us to reduce cost, maximize infrastructure utilization and now will be a great fit with an electric fracturing fleet, which I'll go into more detail later. Our planned average horizontal length per well is projected to increase this year with our turn-in-line averaging approximately 11,200 feet, while the average drilled horizontal length will increase to over 11,400 feet, a year-over-year increase for both. The capital plan for 2020 is projected to maintain production at approximately 2.3 Bcf equivalent per day and provide ample flexibility as we evaluate options for 2021. Consistent with prior years, capital spending is expected to be weighted toward the first half of the year with approximately 60% of the capital spend taking a place across the first and second quarters.

Looking back on some of the fourth quarter's operational highlights. In Appalachia, the team turned to sales 23 wells on seven pads during the quarter from an average horizontal length of over 11,900 feet. This brought the 2019 total number of wells turned to sales to 84 with approximately 60% of the wells located in the wet and super-rich portions of the field, allowing for utilization of existing infrastructure. The wells turned to sales in the fourth quarter were spread across all three areas of the field, covering our dry, wet and super-rich acreage and generated some of our top-producing wells for the year.

This included six of our top-producing wells for 2019. In the wet gas area, we turned to sales 10 wells in the fourth quarter with an average horizontal length of more than 14,500 feet. The wells were strong performers and helped fully utilize our wet gas gathering system in Q4, resulting in lower unit costs. In the super-rich portion of the field, we turned to sales five wells on two pads in the quarter.

These pads are approximately 30 miles apart, flanking the north and south ends of our super-rich position. Both pads have generated strong 30-day rates of more than 15 million cubic feet equivalent per day per well, further showing the consistency of our acreage and ability for repeatable performance in the years ahead. And lastly, in the dry gas area, we turned to sales our highest total producing pad of 2019, where seven-well pad was turned to sales early in the fourth quarter and produced at approximately 150 million cubic feet per day under constrained conditions for the remainder of the year. In addition to drilling some of our longest laterals in 2019, the team was able to achieve new operational efficiency levels with our average daily lateral footage drilled increasing approximately 30% in the fourth quarter compared to Q3 and 36% higher than the full-year average.

In fact, during the quarter, Range experienced our most efficient month for drilling operations, capturing an average daily lateral footage drilled of more than 5,200 feet per day, all while staying within our planned target interval. This substantial increase in daily footage drilled is directly attributed to utilizing the latest directional drilling and drilling fluid technologies for both curve and lateral applications. This type of performance is a key driver in our peer-leading drill and complete capital efficiency for 2020. In completions, during the year, the team completed just under 4,400 frack stages at an efficiency of 6.8 stages per day, which represents an 8% increase compared to the prior year, all while reducing the average number of crews needed.

In addition to improving efficiencies, the completions team continued their testing efforts of an electric-powered fracturing fleet, which resulted in contracting that fleet starting in the fourth quarter. By replacing the diesel fuel with this fleet on the three test pads in 2019, the team was able to capture over $1.5 million in savings while reducing operational noise levels and emissions. When we look at using EPA emissions factors, utilizing this technology versus a conventional fleet becomes impactful, creating a significant reduction in emissions, combining emissions reduction with the ability to fuel our operations with clean burning natural gas, and we see this as a significant win on several fronts and a great next step to achieving our environmental goals. The fleet will be fully utilized in our 2020 program as we operate on pads with existing production, which, again, represents approximately half of our activity this year.

In the fourth quarter, the team also initiated our first efforts to source frack sand directly for our completions. Projecting from our early savings observed and completed and coupled with the cost reduction associated with the electric fracturing fleet is estimated to reduce completions costs by approximately $30 million in 2020, producing yet another layer of durable cost reductions. Lastly, similar to our discussions on prior calls, Range's water recycling program continues to reduce cost and improve efficiencies in Appalachia. In addition to recycling 100% of Range's Southwest PA water, utilizing other producers' water totaled just under 5 million barrels in 2019 and represented a year-over-year increase of more than 12% versus 2018, and as a result, reduced our completion costs by over $10 million.

In addition to the efficiency gains, cost reductions and technology deployment, the teams have remained just as focused on our safety performance. Through training efforts and job task evaluation, the teams were able to reduce contractor, workforce, OSHA recordables by 29% and preventable vehicle incidents just under 15% compared to the prior year. The message from our team is loud and clear. Having a safe work environment is of paramount importance, and we look forward to building upon these results in the year ahead with expanded goals and initiatives.

When you consider the repeatable operational efficiencies captured by the teams, deployment of new technology, water recycling and utilizing pads with existing production, we see this translating into a durable market-leading capital efficiency, producing a drill and complete cost of $610 per foot. On the marketing front, the current natural gas strip is obviously challenged, but we see reasons for optimism as it relates to natural gas fundamentals. Looking out to the balance of the year, with reducing rig counts and frack crews, along with the shift by most producers to spend at or below cash flow and lower year-on-year capex guidance, we anticipate U.S. natural gas supply will decline year over year as we exit 2020, the first decline since the spring of 2016.

On the demand side, additional coal-to-gas switching is leading to record winter gas power burn and additional coal plant retirement announcements. U.S. LNG feed gas recently reached new highs in excess of nine Bcf per day in late January. Looking internationally, we are cautiously optimistic that higher coal-to-gas switching in Asia and Europe and lower pipeline gas imports into Europe can contribute to rebalancing European gas storage this summer.

Looking into next year, a significant slowdown in global LNG supply growth and potentially improved industrial demand in Asia points to improving fundamentals with 2021 international gas prices continuing to trade above $5 per MMBTu. We believe this improving demand picture, coupled with declining domestic supply, should serve to improve domestic natural gas balances and pricing. On the liquids side, Range's fourth quarter NGL realizations increased on continued escalations of premiums at the export dock as well as crop-drying demand for propane and heavy gasoline-blending demand for butanes. Looking forward, starting in April 2020, Range will increase its capacity on Mariner East 2 as we continue to see a significant benefit to international LPG exposure.

International demand growth for 2020, coupled with the lack of U.S. Gulf Coast capacity expansions until later this year, is expected to support strong premiums at Marcus Hook. This is reflected in our 2020 NGL pricing guidance of a premium to Mont Belvieu for Range's barrels. As we wrap up the operations section, I'd like to congratulate our teams for all their achievements in 2019, along with the creative initiatives being executed today, allowing us to deliver on our operational, safety and environmental goals, all while we produce our most operational and capital-efficient program yet.

I'll now turn it over to Mark.

Mark Scucchi -- Chief Financial Officer

Thank you, Dennis. As mentioned on previous calls, our strategic priorities or guiding principles are to fund investments in the business from cash flow to further strengthen the financial position and to protect and growth margins through continuous cost management and innovative sales agreements. Collectively executing on these principles, we believe, can create significant, sustainable stockholder value. First, let's discuss significant strides taken, reinforcing Range's financial foundation.

We've been decisive and early to monetize assets as the first among public peers to sell royalty interests and noncore acreage for $1.1 billion. Scale and cost advantage asset base supported a $400 million increase in commitments under the bank credit facility during the fourth quarter. And in January, we were prepared and moved quickly to issue unsecured bonds, raising $550 million in capital to refinance nearer-term maturities. In the aggregate, this totals over $2 billion in capital brought into the business over the last 15 months, reducing debt by 22%, expanding liquidity by $1.2 billion and extending the debt maturity profile.

Questions are common in this market about the workings of a reserve-based lending facility base and the certainty of current bank commitments. We have consistently made conservative elections to set Range's borrowing base and commitment levels well below the calculated value according to reserve-based lending methodology. At the last redetermination date, the maximum calculated borrowing base under RBL methodology was approximately $4 billion. This compares to the $2.4 billion in commitments.

We will soon have our annual redetermination. And using the latest price assumptions from lenders, we continue to see substantial cushion above both Range's $3 billion borrowing base and its $2.4 billion in commitments. Consequently, we are confident in the durability of Range's liquidity position. We believe Range's debt reduction, refinancing and expanded liquidity creates a long runway several years before there is a need to access capital markets.

Despite creating a long runway, it is not our strategy to passively wait for improved prices, though we do believe visibly declining U.S. production and growing demand will rebalance prices. Nevertheless, asset sales remain a high priority, and we are actively marketing and negotiating multiple packages. These are our formal processes, and we look forward to announcing results.

As is our practice, rather than publicly set a target divestiture amount, we will strive to maximize value for stockholders as quickly as we can. As investors evaluate our plans and objectives for 2020, including possible divestitures, it's informative to recall what we have successfully delivered toward prior plans as well as what we intend to do going forward. Results for the fourth-quarter and full-year 2019 reflect Range's focus and ability to deliver on financial and operating objectives consistent with prior periods, operating efficiency and our close attention to capital discipline, delivered planned production, capital spending better than budget and continuing to drive down unit costs. Capital spending for 2019 beat budget by $28 million.

Turning to cash unit costs. In continuing progress to drive unit cost to and below $2 per Mcfe, in the fourth quarter, Range achieved all-in cash cost of $1.92 per unit of production, including lower LOE, gathering, processing, transport, G&A and interest expense. We delivered on guidance and forecasted trend in unit costs. The quarter-over-quarter improvement of $0.10 per unit and $0.26 per unit compared to the fourth quarter of 2018 are the result of efficiency across the board, led by improvements in gathering, processing and transport.

Over time, we expect a downward trend in cash unit cost to continue. At times, margin-enhancing transportation or sales agreements may cause slight upticks in GP&T expense due to the accounting geography in the income statement. But when that occurs, you will see higher relative expected sales price and higher margins. As an example, this year, Range has capacity on Mariner East 2 slated to come online.

These barrels are currently transported by rail under a net price arrangement. Consequently, when the pipeline capacity is available, that transport cost will be classified as GP&T expense, but it is more than offset with improved margins. It is also worth noting that no incremental production is needed to fill this capacity. To put these unit cost savings in perspective, just assuming 2019 annual production of 833 Bcfe, each $0.01 in margin adds over $0.08 to the bottom line.

For efficient use, direct operating expenses continue to benefit from efficient water handling and the sale of legacy properties. G&A has been reduced through both asset sales and staffing reductions with full-time employee headcount reduced 18% this year. Annual cash interest expense was also reduced by $19 million due to lower debt balances. In the fourth quarter, we recorded noncash impairment charges, reducing book value of proved and unproved properties in North Louisiana.

The noncash charges for North Louisiana result from our strategic focus on the highest-return projects in the Marcellus, the lack of intent to drill the unproved Louisiana acreage, combined with lower commodity prices, affecting the book value of Louisiana proved properties. There were no impairments of the Marcellus. The first step in a GAAP proved property impairment test is to compare undiscounted future net revenue to book value at year-end strip pricing for the Marcellus. Future net revenue exceeds book value by greater than $20 billion or roughly 600%, providing substantial cushion.

As we begin 2020, while near-term commodity prices remain under pressure, Range's resilience and its ability to adapt has been demonstrated. For 2020, Range developed a plan driven by internal cash flow, preserving and enhancing liquidity, maintaining capital efficiency, managing leverage and efficiently utilizing existing infrastructure. In planning these objectives to maximize value from the 2020 capital program, we developed a $520 million capital plan that is focused and efficient, with virtually all capital going to the Marcellus. This 2020 budget is 31% or $236 million lower than 2019's budget, and targets production approximately flat to fourth-quarter 2019.

Range is well hedged for 2020 with over 60% of natural gas protected at an average of $2.64 and approximately 80% of our condensate hedged at $58 per barrel. Additionally, the capital plan is flexible, such that we can and will adapt spending to changes in commodity prices. In summary, Range delivered again on its operating and financial plans, has created significant running room for supply and demand to rebalance prices, recast the cost structure to enhance resilience for a low price environment and continues to work meaningful asset sales with the goal of continuing these trends. Jeff, back to you.

Jeff Ventura -- Chief Executive Officer

Operator, we'll be happy to take questions.

Questions & Answers:


Operator

Thank you. Mr. Ventura. [Operator instructions] Your first question comes from the line of Arun Jayaram with JP Morgan.

Your line is open.

Arun Jayaram -- J.P. Morgan -- Analyst

Yes. Good morning. My first question involves the capital allocation in 2020 versus 2019. As you mentioned in your prepared comments, you're now allocating 51% of the capital to the dry gas assets in Southwest PA versus 36% last year, and it does reflect lower capital allocation to the super rich.

So just wondering if you could talk about the year-over-year changes in that higher capital allocation to dry gas, just given the weakness we were seeing in gas prices?

Dennis Degner -- Chief Operating Officer

Arun, this is Dennis. As we look at the plan, really, year in and year out, it's important that we look at a host of variables on how we consider capital allocation. And one of those being where we have room in the existing gathering system and our ability to fully utilize that and keep our unit costs low. Part of Q3 and Q4 of last year really involved a 65% and 73% of our turn-in lines were really in wet and super rich, so we're now getting an opportunity today to harvest those volumes as a part of the plan that were toward the second half of last year.

That's really critical and key when you think about just the development process as a whole. But as we look toward the 2020 program, there will be 20 -- 50% of the program be in the dry gas, and that is to also utilize some gathering that was -- a project that was starting to be put in place toward the middle of 2019 is in further developing. So again, we'll fully utilize that and look to keep our unit costs low. Lastly, we always keep some flexibility in the plan with our ability to move back into existing pads so that when we do see commodity prices change, we always allow for some flexibility so that we can move back into those pad sites and taking advantage of market condition changes.

But we don't tend to also try and over-correct on the steering with our program because we also know it's key to stay focused on multiple metrics.

Arun Jayaram -- J.P. Morgan -- Analyst

Great. And I just wondered if perhaps you could elaborate a little bit more on the Mariner East 2 capacity. It is -- you mentioned it is driving up your GP&T costs. But could you comment on what you expect is the offset in terms of the NGL price?

Mark Scucchi -- Chief Financial Officer

Yes. Sure, Arun. This is Mark. I'll start, and then hand it over to Alan Engberg, our vice president of NGL marketing.

So I think the first key point to understand is the accounting behind this. It's really geography in the income statement. As I tried to describe in the scripted portion of the call, the current sales arrangement is net price, meaning we are paid a price that is after the cost of transport by rail that is carried by the buyer. When this capacity comes online, it is something that Range can control and optimize.

So in essence, it's a check that we're cutting. It shows up in the gathering-processing transport line item, but we receive a higher price. So net-net, this is a cost saving and margin enhancement because moving NGLs by pipe is cheaper than moving it by rail. So Alan, would you add to that?

Alan Engberg -- Vice President of NGL Marketing

Yes. I would just add to that that the overall attractiveness of access to the international markets is really a differentiator for Range. We're one of only two independent E&Ps in the country that can directly access the export markets. The premiums that we've been seeing at the dock have improved considerably during 2019, and they continue to improve, actually.

We saw premiums. If I go back to fourth quarter of '18, they were rougher $0.055 at the export docks. By the third quarter of '19, they were at $0.07. By the fourth of '19, they were $0.12.

And actually, despite everything going on in the world today, in the larger macro environment, the year-to-date premiums -- as actually published by one of the price reporters in the U.S. here, the year-to-date premiums are actually at $0.15 per gallon. So overall, we've guided higher in our NGL realizations for 2020 because we expect to do much better with continued growth and expansion in our export program.

Arun Jayaram -- J.P. Morgan -- Analyst

Great. Thanks a lot.

Mark Scucchi -- Chief Financial Officer

Thank you.

Operator

Brian Singer with Goldman Sachs. Your line is open.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning.

Jeff Ventura -- Chief Executive Officer

Good morning.

Brian Singer -- Goldman Sachs -- Analyst

Realize that when you think about your cost structure, not all of it is variable. But given the low gas and NGL price environment, just wanted to get a better sense how you debate internally, both what price environment you would need to see or sustained price environment for either a further slowing of activity. Or then, is there some point at which at least wells that may be a little bit more marginal within the portfolio should be temporarily shut in?

Jeff Ventura -- Chief Executive Officer

Well, let me start and then flip it over to Mark. Yes. We're, again, laser focused on making sure that our program is going to be aligned with cash flow. We have multiple scenarios that we'd look at, and we'll be sensitive to that and react in enough time to make sure that that occurs.

Obviously, the changes that we'll make will focus on wells that have better return versus the forward return. And as Dennis said, we'll look at unit costs and all the other things to optimize the program. Team does a good job. If you look at the last couple of years, we've adjusted our program.

We've come in below budget. Let me flip over to Mark.

Mark Scucchi -- Chief Financial Officer

Sure, Brian. I would say there's really two essential elements for Range that come to bear on the question you've asked, and that's, first of all, the flexibility we have. The fact that our gathering infrastructure and long-haul transport is fully utilized gives us a tremendous amount of flexibility. In other words, we're not trying to cover those costs and doing analysis on a sunk-cost basis.

In fact, we have production above and beyond our take-or-pay contract. So again, that gives us flexibility in terms of determining the level of activity in the year and/or, if you were in an extreme scenario, in evaluating shutting in production, what that would mean in terms of your cost structure. And cost structure is really the second main point I wanted to bring back to, and that's with cash unit costs, fourth quarter of $1.92. That puts us in a very good stead in the environment for 2020 and beyond.

We've shown a consistent track record of driving that down. And I would also note that the preservation and expansion of our margins is critical there. If you look at the gross margin, if you will, as a percentage of revenue, that's been sustained even though prices have come down, given the fact that we have driven down absolute costs. The third point I would make there is we evaluate prices, and people are looking at natural gas prices.

It's important to note that, even on an unhedged basis, when you look back at Range's realized price per Mcfe, even unhedged, it was $0.30 above NYMEX for 2019. And if you look back over the last few years, it's anywhere from that $0.20 to $0.30. So again, that gives us a lot of flexibility to adapt to whatever prevailing market prices are.

Brian Singer -- Goldman Sachs -- Analyst

Great. And then my follow-up is also on the cost structure, the capital cost structure. You highlighted a number of the initiatives you were taking in terms of e-fleets and water. And I think you mentioned that the e-fleets are reducing your completion costs by about $30 million this year.

Is that $30 million built into your capital budget? Or would that be an area where you could potentially spend under your budget? And can you talk within the other initiatives that you mentioned, is that's built in or if there's the potential for either further savings relative to that capital budget that you have?

Dennis Degner -- Chief Operating Officer

Yes. Brian, I would say, a significant portion of the cost savings that we're projecting for the year are built into that $610 per-foot assessment that we're communicating today. However, the team always continues to move the goalpost. And I could spend a whole another call's worth of time talking about the good work that the team has done.

And year over year, they continue to drive additional water recycling, taking other operators through a collaborative effort, their water, capturing those additional savings. And really, on the drilling side, same thing. We see that efficiencies that we're planning for, a lot of times, the team is exceeding those expectations through the balance of the year. So from what we're planning for today, would I expect us to have additional savings? It certainly wouldn't surprise me because the team just continues to really do a great job and exceed expectations.

And it's been really the cornerstone of why we've come in under budget the past two years consistently. So we would hope and expect to see some additional savings come to fruition.

Jeff Ventura -- Chief Executive Officer

Yes. I would just -- I would -- referencing what Dennis is saying, we -- the team continues to get better and move the goalpost. So last year, I think a lot of our peers were targeting range cost to drill and complete per foot at, whatever it was, $750 or whatever, and they're still striving to hit that yet. What we did is moved it further down to approximately $600 per foot.

So -- and I have great faith in the team that they'll continue to find ways to lead the pack. We put a new slide in our deck, it's Slide 11, and it's -- looks at -- we talked about peer-leading capital efficiency, and whether you look at it on well cost per lateral foot. And I think, importantly, the new part at the bottom, where you look at total drill and complete capital per Mcfe added, and we put it in there over the last three years or three-year average. And last year, Range was best in the entire basin and great results across three years.

So great faith, the team will do that. And also, like Mark said, that we have flexibility in being able to alter the budget as needed.

Brian Singer -- Goldman Sachs -- Analyst

Thank you.

Jeff Ventura -- Chief Executive Officer

Thank you.

Operator

Jane Trotsenko with Stifel. Your line is open.

Jane Trotsenko -- Stifel Financial Corp. -- Analyst

Good morning, and thanks for taking my questions.

Jeff Ventura -- Chief Executive Officer

Good morning.

Jane Trotsenko -- Stifel Financial Corp. -- Analyst

I just wanted -- yes, on asset sales and royalties, if you can comment on how the market for these assets looks like today than, let's say, compared to a year ago or so?

Jeff Ventura -- Chief Executive Officer

Sure. As I described earlier, we have multiple active processes under way. We've spoken of Northeast Pennsylvania before, the Lycoming county asset, there's discussions ongoing there. We have, obviously, had success in monetizing a small portion of our inventory and resource potential in Southwest Pennsylvania, 0.5 million acres of stacked pay potential there, $1.1 billion in proceeds out of the royalty.

But given the scale of asset, it clearly represents future potential. And then, obviously, an asset that has not garnered its fair share of capital within our portfolio becomes an active candidate. So we do have a process and data room open on North Louisiana. So there are multiple dialogues across multiple assets and projects.

And I think I would look back on Range's track record of being able to deliver on divestitures over the last number of years as an indicator of what we intend to do.

Jane Trotsenko -- Stifel Financial Corp. -- Analyst

Would you generally characterize that there is like more interest for royalties rather than assets?

Mark Scucchi -- Chief Financial Officer

I would not characterize it that way. It depends on the asset base and the location. There are different buyers for different assets. Some operators in a given area may want a bolt-on just to add production to their given area.

It's efficient. If you're in the Gulf Coast, that one is adjacent to petrochemical demand and LNG offtake. So that has appealing interest to both domestic and international players. So it depends on the asset and the location you're talking about as to who the interested parties may be.

Jane Trotsenko -- Stifel Financial Corp. -- Analyst

OK, got it. And then the second question, so the revolver discussion that you had in the prepared remarks was very helpful. I have a question regarding the near-term maturities, and to what extent it would be possible to put them, maybe a portion of that, on the revolver and if it's even an option?

Mark Scucchi -- Chief Financial Officer

Yes, it is an option. As we disclosed, I think, beginning in Q3, we had begun repurchasing near-term maturities on the open market, and we will continue to do that carefully. So that is definitely an option, and we have substantial liquidity to deal with near-term maturities, combine that with refinancing we did early this year, pushing maturities out and expanding the credit facility last fall. And then lastly, and most importantly, the fact that we see substantial cushion to the current borrowing base at current prices and assumptions by the lenders, we feel like we're in great shape as it comes to the debt maturity profile.

Jane Trotsenko -- Stifel Financial Corp. -- Analyst

OK. Got it. Thank you so much.

Operator

Jeffrey Campbell with Tuohy Brothers. Your line is open.

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

Good morning. My first question is there's been a lot of really interesting discussion about cost reduction and a lot of specifics. I just wanted to kind of back up and ask what portion of this leading cost per barrel lateral foot cost surrounds returning to your portfolio of 200 pads as opposed to the other items that you discussed?

Dennis Degner -- Chief Operating Officer

Yes. Jeffrey, this is Dennis. Year in and year out, kind of trying to touch on it during the call this morning, but this year's activity will represent about 50%, of it will be going back to pads with existing production. But if you were to look back over the past several years, it can be as much as 50% on a year-in, year-out basis.

So we look at our cost savings, are there cost savings we're capturing due to this? Absolutely. But what we see, though, is that there's a fair bit of durability in the cost savings that we're capturing this year that are repeatable year in and year out. And that's just one of them. The other is, clearly, the team being creative and looking at sourcing sand directly for our completions operations.

That's an initiative that may not necessarily be new to the E&P space. However, we feel like patience has kind of paid off for us in that regard because of where the market is from a profit standpoint. We see there being a fair bit of durability then and that going into 2021 and beyond. So as we start to stack up electric fracturing fleets, the technology the drilling team is deploying, moving back into existing pads, we see there's a fair bit of durability in capturing these cost savings, not only this year but also in the years to come.

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

OK. And then regarding North Louisiana, bearing in mind that it sounds like that it's apparently or potentially for sale. Do you have any midstream volume requirements in 2020 that -- and can you meet them until a sale can close? Just wondering about midstream down there.

Mark Scucchi -- Chief Financial Officer

So I think, as we've alluded to before and was disclosed early on at the time of the acquisition, there are commitments on processing volumes. So those processing volumes are not fully utilized right now, but that cost is already reflected in Range's GP&T line item. So even though we are paying for some processing capacity that's not fully utilized, we've still driven the cost from $1.51 in the fourth quarter of last year, down to $1.39. So we did have, early this year, a $40 million to $50 million portion of that commitment roll off.

So that will be an improved run rate for 2020, and we'll continue to certainly work to optimize that in the context of a potential sale.

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

OK, great. I appreciate that color. Thank you.

Dennis Degner -- Chief Operating Officer

Thank you.

Jeff Ventura -- Chief Executive Officer

Thank you.

Operator

David Deckelbaum with Cowen. Your line is open.

David Deckelbaum -- Cowen and Company -- Analyst

Good morning, guys. Thanks for the time.

Mark Scucchi -- Chief Financial Officer

Good morning.

David Deckelbaum -- Cowen and Company -- Analyst

Just to expand a little bit more. So I understand the multiple years of capital efficiency. Being on 50%, your budget on existing pads this year is obviously helping you get those well costs down on a blended basis. If you were just to remain on existing pads, how long could that program sustain for?

Alan Farquharson -- Senior Vice President, Reservoir Engineering & Economics

Yes, this is Alan Farquharson. Let me kind of take that question a little bit. First of all, we've been, as Dennis mentioned a little bit ago, if you look at our track record over the past several years, we've probably been about 50% of the wells on the pad. Probably on average, we have over 200 pads out there.

And on average, we're probably in the five to six wells on an existing pad. So we built these pads to handle up to 20 wells. So I think the runway is very long on our ability to be able to keep that happening. So I think our low cost aren't necessarily reflective of going back on pads for 50% this year.

It's been built into the entire cycle. So you can always see, we're always building some pads every single year, if you're only going back on half the wells to be able to get there. So you always have some of that opportunity down the road. So eventually, you'll be in a situation where you won't be able to -- you won't be building any new pads.

So costs actually could come down as you think through the longer cycle.

David Deckelbaum -- Cowen and Company -- Analyst

I guess, I'm wondering, the market is obviously not particularly robust right now. Why isn't that percentage increasing more as a way of sort of augmenting your margins?

Alan Farquharson -- Senior Vice President, Reservoir Engineering & Economics

Well, I think part of that starts with -- I'll go ahead and start with that. I think part of that starts with just the way the development plan is set up. The permitting process in Pennsylvania is somewhat cumbersome and takes a fair amount of time. So a lot of the pads have already been built.

They may have been built in 2019. And as a result, you're now just getting to drill the wells in 2020. So I think you'll see a change over time. And it's just a matter of the way the development plan is put together and just the timing of everything.

And of course, you want to be able to efficiently use your gathering system as well.

Mark Scucchi -- Chief Financial Officer

Comes back to cash flow. Where there's room in the gathering system where you can get that production online to market, and where the netback and quickest payback period for those dollars invested are, it boils down to the cash flow.

Dennis Degner -- Chief Operating Officer

Yes. And then I'll follow along here, lastly. But I think a piece of this -- it's ever evolving. So when you look at the lateral lengths and how they've increased over the past, let's just say, two to three years, not only for us but for a lot of folks, but especially Range and the efficiencies associated with that, we're seeing the opportunity to reduce the number of pad sites that we're needing to build and touching on that a little bit with just the average lateral lengths increasing, the gathering system.

So all of this really becomes a very integral piece of the planning process as we think about, as Mark touched on, efficiently using then the gathering and infrastructure in our processing.

David Deckelbaum -- Cowen and Company -- Analyst

And then just my second question. As you look at the landscape right now in Appalachia, you've talked a lot about initiatives to delever through asset sales. You've had a lot of success with noncore asset sales and overriding royalty into your sales. On the other side of it, I guess, when you think about some cost control, as some of your peers look at insolvency or, obviously, the market is undergoing a lot of distress, are you seeing opportunities to renegotiate things with your gathering partners, with your processing partners? And do you foresee opportunities to renegotiate with long haul as well?

Mark Scucchi -- Chief Financial Officer

I think just getting a good beat on our situation today is important, and then we can consider how renegotiations may play into that going forward. With over a decade of development of the Marcellus and the signing of the earliest gathering, processing and transport agreements here, you're at the stage where some of those early agreements are already at their option to extend or drop at Range's election. So beginning this year, next year, and kind of as a steady cadence thereafter, we have portions of capacity that we can allow to just drop off that do not require renegotiation. That's just our option.

You also have elements of the cost structure, particularly on the gathering side, we've spoken to before, where some of the capital recovery pieces begin to drop out, and the costs do decline over time. So the glide slope there is in our favor for a long-running, steady decline in the cost structure on the gathering-processing transport. But I'll let Dennis speak to more detail on renegotiation.

Dennis Degner -- Chief Operating Officer

Yes. I think, ultimately, I'll kind of step up higher level here for a second. But we are working always on ways to optimize our portfolio. And that doesn't -- that includes all aspects of the gathering, the processing and the transportation side of our business.

As Mark indicated, being an early mover, there are packages that we're seeing the opportunity to set the -- see -- let those expire, and then also be strategic about how we consider renewing or adding transport to our portfolio down the road sometimes. So we like where we're at. We're exceeding our FT commitments today. We're maximizing our portfolio.

However, look, our part -- these are our partners as well. And so we're always actively looking for ways that we can renegotiate. We can also look for ways for strategically reducing costs, making sure that we're -- we have the right cost structure for this cycle. As we put in our slide deck, we already had a $0.12 reduction in our GP&T cost over the past 12 months, when you look from Q4 '18 to Q4 '19, and we're projecting a similar trajectory in the years ahead.

So it will come -- our cost reductions will come through multiple avenues, one of which could be renegotiations.

David Deckelbaum -- Cowen and Company -- Analyst

Thank you, guys.

Mark Scucchi -- Chief Financial Officer

Thank you.

Operator

We are nearing the end of today's conference. We will go to Sameer Panjwani with Tudor, Pickering, Holt for our final question. Your line is open.

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

Hi, guys. Good morning. I wanted to ask on the 2020 outlook. I know there's been some back and forth on this call here but, I guess, just to clarify, do you see the current program as free cash flow neutral or positive at current strip? And then can you also quantify the buffer you have in terms of production above your midstream commitments?

Mark Scucchi -- Chief Financial Officer

So as it relates to the 2020 plan, when we rolled that out in January, obviously, prices were somewhat higher. And that program was designed to be cash flow neutral to positive at strip prices at the time. Again, given the prices have come down somewhat, it would require some adjustment to that plan. And as Jeff and Dennis and I have each described, our primary motivating factor, kind of the guiding principle, is to self-fund the program to be cash flow neutral, cash flow positive throughout the cycle.

So there is flexibility, and it would be our intent to make adjustments to that plan as need be over the course of this year to make sure that we are self-funding that to the maximum extent possible.

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

OK. And are you able to quantify that buffer you have in terms of production above your midstream commitments?

Mark Scucchi -- Chief Financial Officer

So on the FT side, commitments are roughly 1.6, and production, about 1.8. So you got a good 10% buffer.

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

OK, got it. And then on the asset sales side of things, you mentioned there is a data room open for Louisiana, and the Northeast Pennsylvania asset has been on the market for a while. Do you happen to have PV-10 values as of the end of 2019 for each of those? And just from a higher-level standpoint, when you're kind of marketing these, are you hoping to get some level of undeveloped acreage kind of ascribed in the transaction values?

Mark Scucchi -- Chief Financial Officer

I mean, yes, we have PV-10 values, but we're not going to set any markers out there for individual assets or the aggregate asset sale proceeds. So we will just continue to seek to maximize the value so that it's both deleveraging, enhancing to the cash flow going forward and just monetize those as quickly as we can.

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

OK. Thank you.

Jeff Ventura -- Chief Executive Officer

Thank you.

Operator

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

Jeff Ventura -- Chief Executive Officer

Yes. I just want to thank everybody for participating on the call, and feel free to follow up with additional questions. Thank you.

Operator

[Operator signoff]

Duration: 57 minutes

Call participants:

Laith Sando -- Vice President, Investor Relations

Jeff Ventura -- Chief Executive Officer

Dennis Degner -- Chief Operating Officer

Mark Scucchi -- Chief Financial Officer

Arun Jayaram -- J.P. Morgan -- Analyst

Alan Engberg -- Vice President of NGL Marketing

Brian Singer -- Goldman Sachs -- Analyst

Jane Trotsenko -- Stifel Financial Corp. -- Analyst

Jeffrey Campbell -- Tuohy Brothers Investment -- Analyst

David Deckelbaum -- Cowen and Company -- Analyst

Alan Farquharson -- Senior Vice President, Reservoir Engineering & Economics

Sameer Panjwani -- Tudor, Pickering, Holt & Co. -- Analyst

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