Welcome to the Range Resources second quarter 2018 earnings conference call. All lines have been placed on mute to prevent any background noise. Statements made during the conference call that are not historical facts are forward-looking statements. Such statements are subject to risk 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.
Thank you, operator. Good morning, everyone, and thank you for joining Range's second quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer, Dennis Degner, SVP of Operations, and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we posted on our website. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system. Please note that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. For additional information, we've posted supplemental tables on our website to assist in the calculation of EBITDAX, cash margins, and other non-GAAP measures. The supplemental tables also include detailed information on realized pricing and transport expense for all products.
You can also find detailed hedge information on the website under the Investors tab to assist in the calculation of hedging gains and losses. With that, let me turn the call over to Jeff.
Thanks, Laith, and thanks everyone for joining us on this morning's call. Looking at our second quarter results, we continued to build on the operational and financial success we saw in the first quarter of the year. Our cash flow per share increased 22% over the prior year, driven by consistent results out of Southwest Pennsylvania, further unit cost improvements, and better realized prices. I'll provide a few comments on the quarter and the progress we're making on our strategic goals and five-year outlook before turning it over to Dennis and Mark. Reflecting on the quarter, we continue to see meaningful improvements in cash flow per share with production and cash margins both higher versus last year. The key driver behind this year-over-year increase in margins was the $20 per barrel increase in oil price, which has pushed NGL prices to levels not seen since 2014.
As a result of this price strength, coupled with our advantaged NGL capacity for ethane and propane, we are increasing our expected NGL realizations to the high end of our previous guidance. 46% of Range's pre-hedge revenue for this quarter came from liquids, the majority of which was from our Appalachian NGL production. It's understandable that Appalachian is often seen as a gas play since the basin is one of the largest natural gas fields in the world. However, I think it's important to recognize the differentiated position Appalachia has with in-basin fractionation, control of purity products, and access to international markets.
This type of market does not exist in any other major U.S. liquids play, as other basins typically send a wide-grade barrel to the Gulf Coast. We think the unique nature of the Appalachian NGL model will become evident over the next year or so as purity products with access to international markets should garner premiums to typical wide-grade NGL production you see from other plays. Back to the quarter, worth mentioning, Range's natural gas differentials are also improving compared to expectations back in April as more of our gas is transported to strong markets, and in-basin sales are seeing meaningful basis differential improvements. A result of Range's guidance on calendar 2018 gas differentials has improved to approximately $0.10 under NYMEX compared to $0.32 last year.
These benefits are being realized as Southwest Appalachian gas markets start to benefit from new pipeline capacity after years of constraint. Operationally, the team continues to turn in line high-quality Marcellus wells, which have increased the Southwest second quarter production, up 30% compared to this time last year. As most of you know, the downtime we experienced on the Mariner East 1 NGL pipeline and the Leach XPress natural gas pipeline created significant challenges, but the team was able to work with our various midstream and processing partners to maintain production in the field. I'm incredibly proud of the team's achievements, delivering a solid quarter despite these challenges. We believe the substantial year-over-year growth expected out of the Southwest area while living within cash flow demonstrates what our core assets are capable of and gives us confidence in the long-range outlook, which is underpinned by our Marcellus assets.
Turning to the five-year outlook, let me reiterate again what the outlook represents. It represents what our assets are capable of at year-end 2017 strip pricing under what we believe are conservative estimates as Range has a long track record of improving well productivity and extending lateral lengths, which is not included in this forecast. Looking at our base case five-year outlook, we see expanding margins through a lower cost structure as Range leverages its high-quality inventory and infrastructure. These improvements are led by reductions in our GP&E costs through increased utilization of existing transportation, gathering, and processing capacity. We also expect meaningful reduction in interest expense, both in absolute terms and per MCFE, as we increase cash flow and reduce debt. At the same time, G&A per MCFE should improve as we become more efficient and leverage our existing personnel.
Combined, we see these cost reductions equating to enhanced margins over the five-year outlook, starting later this year as we fill the last of our natural gas firm transportation agreements. We believe these anticipated improvements in margin, coupled with Range's low decline rate and maintenance capital requirements, positions us to generate sustainable free cash flow. Given our vast inventory of high-quality Marcellus locations, we believe we're in a unique position to not only deliver on a plan of free cash flow and growth, but to continue this beyond the five-year outlook into a market that will see others exhausting existing core inventories. While we think this outlook for free cash flow, improving returns, and organic de-levering with a high-quality inventory is a compelling story, leverage does not come down as fast as we'd like. That's why we're actively pursuing asset sales that will enable us to fast-forward leverage.
We're targeting potential asset sales in Northeast Pennsylvania and Southwest Pennsylvania that will support our near-term goal of getting leverage below three times as we ultimately move towards an investment-grade leverage profile. We believe that prudently lowering leverage is a key step in addressing the disconnect we see between our current equity value and what we believe is the true intrinsic value of our business. These potential asset sales should fast-forward the time in which we do that. We are making good progress on the operational and strategic goals we've set for ourselves. We're excited about the progress we're seeing. To further support these efforts, we announced a couple of initiatives earlier this month that will result in Range further strengthening its management team and board.
Range plans to add an Executive Vice President to the senior management team, who will provide added experience and perspective to the team. We also announced that in cooperation with our largest shareholder, SailingStone, we'll be adding two new independent board members to provide additional insight and perspectives. Board refreshment is a topic we have discussed with many of our shareholders. We obviously agree that routinely adding new perspectives and ideas to the board is good corporate governance and makes for a well-rounded board. Similarly, we have split the roles of Chairman and CEO. Put simply, we're committed to being good stewards for the shareholders, which includes engaging with our shareholders in active, open discussions and making changes that improve the company. Based on the ongoing active dialogue that we've had and will continue to have with our shareholders, we believe these changes have been well-received.
We've seen a lot of change over the last six months. Each of these has been a purposeful change that I believe will make Range a better, stronger company. The Range team, from the board to senior management to the field, remains focused on translating our incredible inventory into increased shareholder value. Like I said on the last call, I truly believe that we'll see Range valued as a top-tier E&P company again. We're working tirelessly to make that a reality. I'll now turn it over to Dennis to discuss operations.
Thanks, Jeff. Looking back on the second quarter, our Appalachian North Louisiana teams turned to sales 43 wells across our Marcellus and Terryville acreage positions. As we outlined on our last call, first sales was initiated on the majority of these wells during the second half of the quarter, generating a second quarter production of 2.2 BCF equivalent per day. This puts us in line to deliver on our 2018 plan of 11% year-over-year growth. We expect the third quarter to be at 2.22 BCF equivalent per day. Achieving our production goal in the second quarter was done despite two significant third-party infrastructure outages for both gas and NGLs.
On June 7th, there was a rupture of the TransCanada Leach XPress pipeline that resulted in approximately 1.5 BCF per day of natural gas to be diverted back into the Appalachian Basin, including 300,000 MMBTU per day of Range's production. As Jeff indicated, through our portfolio of transportation options and customer outlets, the marketing team was able to reroute our production as needed, selling more of our natural gas in Appalachia, minimizing the effects of this outage on our production. The line was put back into service on July 15th with our 300,000 per day of production returning to a normal state of operation and flowing to the Gulf Coast. The second infrastructure issue occurred when operation was suspended on Sunoco's Mariner East 1 natural gas liquids pipeline.
As a result, we lost access to capacity on Mariner East 1 for 40,000 barrels per day of ethane and propane combined for almost two months during the second quarter. As one of the largest NGL producers in the U.S., Range has taken a portfolio approach to the sale of its purity products. The marketing team identified alternative markets for Mariner East ethane volumes and sold some of the ethane as natural gas. For propane, Range has access to another local pipeline and rail cars that continue to provide access to international markets via the Marcus Hook Terminal, as well as various domestic markets. By using these alternative methods to reach customers during the downtime, we were able to realize propane prices that were on average above Mont Belvieu index, although with a slightly higher transportation expense.
On June 14th, the Pennsylvania Public Utility Commission voted unanimously to allow the Sunoco Mariner East 1 pipeline to return to service, shifting our ethane and propane sales to normal operation. Just as the team is delivering on production expectations, our capital spend is also on track and in alignment with our 2018 plan. At the midway point for the year, we are a little over 50% of our planned D&C spend as drilling efficiencies drove higher first half of the year activity. I'll spend a little more time in a minute discussing these efficiencies and the good work from our operations team. Our capital budget for the year remains unchanged at $941 million, with 85% directed toward the Marcellus. Looking back on the second quarter, our operational highlights are similar to prior quarters. Our Appalachian drilling team continues to build upon their prior successes.
In the second quarter, the team drilled their best horizontal footage day at 6,349 feet in 24 hours. This record falls into a long list of other 5,000 to 6,000-foot days and further demonstrates the consistency of our Marcellus operation. In addition to setting a 24-hour record for lateral feet drilled, the team also successfully drilled 12,084 feet as the average lateral length in the month of June. This was the best average lateral length for a given month in the program and shows the direction we're headed in the coming years. This all translates into a reduced dollar-per-foot drilling cost as the team drills the longest, fastest, and lowest normalized cost wells in our history. On the completion side, the team was hard at work as well, placing 1,738 frac stages at just under seven fracs per day.
This is a 35% increase in total stages and a 10% increase in efficiency compared to the same time just one year ago. For production, the team turned to sales 39 wells in the second quarter from eight pad sites covering our dry, wet, and super-rich Marcellus acreage. In the dry gas area, 28 wells returned to sales from five pad sites. The average IP for these 28 wells was 20.5 million cubic feet per day from an average lateral length of 7,800 feet. Similar to prior well results we've discussed, four of these five pads were drilled on sites with existing production. As we've shared on the past calls, this approach saves upfront capital costs for roads, pads, and facilities while saving on gathering costs through fully utilizing the existing infrastructure.
As we look back on the first half of the year, along with our forecast for the remainder of 2018, we estimate a capital cost reduction of $7 million based on the use of the existing infrastructure for new wells. This is one of the many efficiency and cost reduction initiatives we expect to see in the years ahead as we develop our Appalachian Marcellus and stack pay opportunities. In the wet area, an additional two pads were turned to sales. The first pad consists of five wells with an average IP of 43.2 million cubic feet equivalent per day from an average lateral length of nearly 12,000 feet. The second wet area pad turned to sales in Q2 came online in the last week of the quarter with production established from only three of the six wells.
The three wells reached an average IP of 33.6 million cubic feet equivalent per day from an average lateral length of over 11,000 feet. We look forward to sharing the results of the remaining three wells at our next call as they establish production early in the third quarter. Lastly, in the super-rich area, production was initiated on three remaining wells from a five-well pad we discussed in the last call. The three wells came online with an average IP of 33.7 million cubic feet equivalent per day from an average lateral length of 13,700 feet. These wells were instrumental in our increase in condensate production for the quarter, with over 60% of their production as liquids. These wells are flowing under constrained conditions and cleaning up as planned.
I believe all of these results are good examples of the type of lateral lengths and well performance we expect for our 2018 program. Before we leave Appalachia operations, I wanted to look back on the continued performance from three key pads turned to sales a year ago. The first is located near the future Harmon Creek processing plant in northern Washington County that should be operational later this year. On this pad, we turn to sales four wells with an average lateral length of 9,200 feet. One year later, this pad continues to be a strong producer, with the wells currently producing above the normalized type curve by 14%. We expect to see more wells like this as we further develop the acreage around the new processing plant. The second pad is located in the heart of Washington County.
It consists of four wells producing from an average lateral length of 9,500 feet. This pad was drilled around prior developed pads, one year later, continues to exceed the normalized type curve by 35%, further supporting the team's ability to improve on prior well results. The third pad is located in western Washington County, where we turn to sales seven wells with an average lateral length of 10,700 feet. These were our longest laterals in the super-rich area at the time. One year later, these wells continue to outperform the normalized type curve by 13%, with the pad still producing over 1,000 barrels of condensate per day. With condensate selling for WTI less $6, the current economics of these wells are obviously excellent. We're excited to see production like this from our program that highlights the quality of our acreage position.
In North Louisiana, the division completed and turned in line four wells in the second quarter, with two wells scheduled to turn in line in the third quarter. As we look back on the year-to-date Terryville performance, our average well results are producing in line with our normalized type curve published earlier this year. We have one drilling rig active in Terryville with a frack crew utilized as needed, which will continue to be our approach for the remainder of the year. Even though our activity in North Louisiana is limited this year, the team is laser-focused on improving results. A few recent examples of their dedication during the quarter are the drilling team increasing drill footage per day by 13.5% versus the 2017 average, by beating the direct operating cost target by 10% year-to-date.
These operational accomplishments for both divisions would not be possible if not for the dedication of our Range team in the field, our technical support in the office, and the help of our service partners. In closing, as we reach the midway point in 2018, we are on track with both production and capital spend as we continue to drill and produce our most cost-effective and operationally efficient wells. I'll now turn the call over to Mark to discuss the financials.
Thank you, Dennis. Financial results for the second quarter were consistent with our seasonal expectations and show progress on a number of strategic fronts. These results were driven by operating activity on pace with our announced 2018 plan, and we believe keeps us on track to drive growth from the capital program set within cash flow. Investment decisions are guided by core principles of disciplined capital allocation, which directs dollars to projects with competitive risk-adjusted rates of return. Efficient operations and diligent efforts in marketing production drove increased revenues, controlled costs, and improved cash margins for the second quarter. Analyst cash flow was $237 million for the second quarter and represents an increase of 22% over second quarter 2017 for both absolute cash flow and cash flow per share. EBITDAX was $291 million, an increase of approximately $51 million over second quarter 2017.
Increased cash flow was driven in part by higher realized commodity prices, higher volumes, combined with ongoing cost controls. Average realized price per MCFE, pre-hedge, net of transportation costs, improved $0.17 compared to the same quarter prior year. Looking at unit costs for the quarter, total cash costs were $1.82, excluding the impact of changes in accounting treatment of certain processing contracts. LOE, production taxes, and interest expense were essentially flat compared to the same quarter prior year. Cash, general, and administrative expenses improved by about $0.01. Including stock-based compensation, G&A improved by $0.06 in MCFE. As you will recall from the first quarter, new accounting guidance has changed the presentation of certain gathering, processing, and transportation expense starting in 2018.
The net impact of this change is neutral to margins, with offsetting increases to revenue and to GP&E expense of $0.21 in MCFE during the second quarter. Adjusting for this change in comparability, GP&E expense increased $0.06 in the second quarter as compared to the same quarter last year. This is mostly attributable to new transportation capacity coming online in 2018, which is offset by higher prices received as a result of this capacity, enabling sales into better markets. Non-cash impairment charges associated with unproved acreage exceeded second-quarter guidance. Approximately $50 million of the expense relates to expiring acreage in certain North Louisiana extension areas that do not merit additional capital to extend leases at this time.
These charges represent the book value of acreage expiring through the end of 2018, and the higher-than-guidance second quarter is a function of timing as we made the decision to allow these leases to expire, causing the recognition of the full 2018 exploration expense. For the third quarter, anticipated corporate unproved exploration expense returns to a more normalized $8 million to $10 million. At the end of the year, estimated acreage in North Louisiana remains consistent with current disclosures at approximately 150,000 acres. Looking ahead to the third quarter, we expect to achieve consistent or better unit costs. The most significant unit cost, GP&E, will be influenced by the timing of our final contracted firm transportation capacity coming online. Cost control, combined with expected better pricing, should result in continued margin expansion.
Turning to the balance sheet, leverage, as measured by debt to EBITDAX, was 3.5 times at the end of the quarter, a sustained improvement from 3.7 times at year-end and flat to the first quarter. Given seasonality and the cadence of drilling activity, we did outspend quarterly cash flow. However, expected annual capital expenditures remain in line with budget at $941 million and less than estimated annual cash flow. We anticipate debt reductions from free cash flow during the second half of this year. In addition, asset sale efforts discussed on recent calls are progressing, and we continue to believe we will have one meaningful asset sale to announce in coming months. In summary, our focus remains on converting consistent drilling success into tangible shareholder returns. From a financial point of view, a cost-effective, resilient capital structure is the foundation to those efforts.
Drilling success achieved with Range's existing inventory, when coupled with safe, efficient operations and rigorous capital management, we believe will yield predictable and growing cash flow. Range's deployment of future cash flow, whether into drilling, debt repayment, or returning cash to shareholders, will vary over time, but it will be underpinned by a disciplined, thoughtful allocation process. Jeff, back to you.
Operator, with that, we'd be happy to answer questions.
Thank you, Mr. Ventura. The question-and-answer session will now begin. If you would like to ask a question, please indicate by pressing the star key, then one. We will take as many questions as time permits until the end of the call at 10:00 A.M. Eastern Time. If you are on a speakerphone, please pick up your handset before asking your question. If you would like to withdraw your question, please do so by pressing the pound key. Once again, press star one to ask a question. Your first question is from the line of Douglas Leggate with Bank of America, Merrill Lynch.
Thank you. Good morning, everybody. Jeff, thanks for all the color on how you're thinking about asset monetizations. I wonder if I could just dig a little deeper on just to the extent you can, how you see the current market in the wake of the Chesapeake deal in particular. I guess specifically, again, to the extent you can, how you feel about whether you expect your likely disposals that you can see line of sight for currently to be acreage predominantly or acreage with production, in which case I should be thinking about cash flow, and I've got a related follow-up, please.
Yeah. As you might expect, I'm going to do it at a higher level. I think the quality of the asset's really critical. I think if you look at the quality of our assets versus the Chesapeake deal, there's really no comparison. You can look at it, recoveries per 1,000 foot, cost per 1,000 foot, cost structure. I think quality is really important. I think that's not analogous at all. The other thing I'll say, and this is at a very high level, so I'm not sure if this will affect your follow-up question, but feel free to ask it. In my call notes, I said our near-term goal is to get leverage below three times. I'll say that we expect it by year-end, and we'll be able to accomplish that.
Yeah, very high level.
I know you, Doug. I know you're going to follow up and ask like five times.
Well.
Let me answer. Go ahead with the second question.
I'll try not to be too predictable. The one asset obviously that you didn't mention specifically was Terryville. Obviously, you've got a decline rate there that you've signaled, I think, pretty well to the market. Limited activity. You're obviously managing a decline rate. How should we think about the role of Louisiana in the go-forward portfolio? Again, obviously at a fairly high level.
Yeah.
I'll leave it there.
Yeah. Great question. Again, very early this year. Given the results we saw in Terryville that were below expectations, we slowed way down in Terryville and allocated even more of our capital to the Marcellus. The clear focus being the Marcellus, but we did keep one rig there. The other thing we did that we talked about is several changes to the team. Dennis Degner now leading operations, Scott Chesebro leading the office in Houston, and there's been several others. I think those guys are making good progress. We're going slower. There's a number of things we're trying at a high level. By year-end, we'll have a good feel for what that is. Then we'll look at the competitiveness of the Louisiana properties against our portfolio. I think Dennis and Scott are doing a great job.
Also going back to the original question, we want to reduce leverage. We want to get below 3 times in the near term, and we expect we'll be able to do that. As I think I said in my notes, we have processes. We're actively pursuing various things in Northeast Pennsylvania and Southwest Pennsylvania to do that.
Jeff, we appreciate everything you're trying to do here, obviously, I don't want to press you too much on this. Just to be clear, is Terryville off the table or is it a candidate for sale at some point?
Right now in the short run, what we're saying is, in the short run, our focus is on Northeast Pennsylvania and Southwest Pennsylvania. Terryville will look at how those returns are either later this year or early next year, make that decision. If you look at our history, there's plenty of history to look at, basically $4 billion in asset sales really over roughly the last decade. When projects aren't competitive, then we tend to sell them. It comes down to can the projects that we have compete on an economic basis with things we have in our portfolio.
Thank you. I'm going to ask one more, if I may, just real quick, it's just really I want to finish on a positive note because obviously you guys, I don't know how the heck you did it, you managed to navigate these pipeline issues fairly well, it seems, relative to our expectations for sure. Congratulations on that. I just wanted to get your perspective looking forward. Do you see any other pipeline issues or challenges ahead of you? Or do you think that we're pretty much past the worst at this point? I'll leave it there. Thanks.
Well, thank you, Doug. I was teasing. Very much respect your work, you do a great job, and we appreciate that. Again, thank you for the positive comments. It was a very tough quarter, I give a lot of credit. Our marketing team really did a great job and operational team of overcoming two really big issues. Remember, 40,000 barrels per day on Mariner East 1 is a lot. That's a big advantage we have of being able to move those products to international as well as $300 million per day on the gas pipeline and then being able to move that and really almost not miss a beat, keep production up, and beat price across the board for all products. Great accomplishment by the operations and the marketing team. Appreciate your comment.
If you look at us, I think we're in a great position. There's really only one more major pipeline to come on, that's Rover. Rover should be on sometime in the third quarter. When you look at infrastructure concerns for Range, they should be behind us. In fact, if you look into 2019, we should be in a significantly enhanced and better position than we have been, in that we won't be waiting on pipeline projects or expecting pipeline projects. Our acreage will be predominantly held, we'll have really that much more flexibility as we get into 2019. It's great having all those infrastructure projects behind us. We're now looking at realizations where we've been able to increase our expectation for what our NGL barrel will be to the top end of the range. Our gas differentials are coming in, almost NYMEX pricing.
We're getting condensate for near NYMEX pricing. It's great to be in that position where a lot of those infrastructure constraints are behind us. We've got a high-quality inventory with the optionality of being able to drill the liquids-rich part, as NGL prices are, like I said, levels we haven't seen since 2014, coupled with really high-quality gas acreage.
Jeff, thanks for the very full answers, guys. Congrats again. Thank you.
Thank you, Doug.
Your next question is on the line of Brian Singer with Goldman Sachs.
Thank you. Good morning.
Hello, Brian.
I wanted to start with regards to the lateral length here. When you talk about the upside to lateral length relative to your five-year guidance, A, can you give us a sense of where you're thinking about lateral length on average in 2019 and 2020? B, more philosophically, if you decide to deploy longer laterals, since it seems like that's the direction you're heading, would you look to exceed your five-year growth forecast based on drilling the same number of wells or meet that forecast drilling fewer wells and potentially spending less capital?
Yeah. Let me answer the second question first and flip it back to Dennis for more detail and insight into lateral lengths. I think what it says is we have a lot of upside. In terms of going forward into the five-year plan, we'll have a lot of optionality. To the extent we drill longer laterals, and my full expectation is that we will, our growth should be more capital efficient. Again, our number one goal is to delever and get leverage down and drive that. More capital efficient growth will enable us to do that. Our plans are to spend within cash flow. Obviously, if we have better capital efficiency, we can get good growth for less dollars or help us delever faster. Let me turn it over to Dennis for some granular comments.
Yeah. Good morning, Brian. We're really excited about the advancements that the operating team has made on our lateral lengths, and we continue to see that advance. If you think about it, just 12 months ago, we were announcing that we had drilled our first successful 15,000-foot laterals, had those completed and turned in line. In the last quarter, we made the announcement that we had drilled our next two longest, one at 17,800 feet and another one at 18,100 feet. Both of those wells are in the process right now of being completed. We hope to have the results of those to announce at our next call. Should be exciting for the organization. As we look forward, our five-year outlook has really been a conservative approach to more 10,000-foot lateral type vision.
We know that as we continue to see us drill longer laterals, we're going to continue to advance that ball further and basically drill long laterals because it makes a lot of sense from a dollars per foot basis as we develop the mineral and extract it here. You'll see movement along the way. We're going to try and put longer laterals in as much as we can. It's just a more efficient operation for us.
Great. Thank you. My follow-up goes back to the deleveraging points from earlier here. Can you provide any details on corporate structures that you may be, or the structures of the asset sales that you may be considering beyond a straight sale? Then post-asset sale, if the balance sheet and the leverage gets down to three times, how would you expect future deleveraging to be accomplished? How much of that would you depend on EBITDA growth versus how much would you depend on operating free cash flow?
Thank you, Brian. This is Mark. I'll try to answer those questions. I guess, first of all, in terms of the structures we would consider, we're not going into a great deal of detail on that just yet. I think what's most important perhaps is to say what we won't do, that is do anything that would impair the efficiencies and the blocked up cost-efficient nature of our Southwest Pennsylvania position. We certainly believe that half-million-acre footprint presents a very long-term drilling inventory, presents value opportunities that we can pull forward, and other ways to perhaps monetize a piece of it and accelerate that deleveraging profile. As it relates to your second question on effectively what's the pace of our deleveraging? How does that look? The five-year outlook, as we've talked about before, is a scenario, a plan at strip pricing.
We can achieve our leverage targets through free cash flow. Ultimately, our decisions will be driven by what the best returns are for invested capital, what we believe will maximize shareholder returns. As we achieve our near-term objective of getting below three times, growth will be driven by cash flow, and what our deleveraging becomes over that five-year outlook, of course, is a function of price, pace of drilling, and so forth. We will, really beginning in 2019, have tremendous flexibility on what the pace of drilling looks like, given that we have no further firm transportation or infrastructure commitment. That's a good line of sight to achieving our long-term objective of low two times leverage.
When you say the growth will be driven by cash flow, is that based on a free cash flow objective or spending within cash flow?
Yes. Generating free cash flow.
Great. Thank you.
Thank you.
Your next question is from the line of Ron Mills with Johnson Rice.
Morning, guys. Just a question. I think you highlighted, Dennis, having about $7 million of savings over the rest of the year by drilling off existing pads. Can you talk about, in addition to the cost efficiencies you referenced, any thoughts about the potential uplift from productivity as you go back into preexisting pads and move into a full development stage on those?
Yeah, good question, Ron. I think as we look back over just the results that we looked back for the past 12 months, those are great examples. Clearly not all of those have been scenarios where we moved back onto pads with existing production. One of them was definitely right in the heart of prior development, and one was adjacent to a prior pad site, and we're above the normalized type curve by 35% in one of those scenarios, and I think it was 13%-14% on the other two. The team has really demonstrated a strong ability to continue to, whether it's big data tools or just ongoing technical evaluation, to build upon the well results that we see year-over-year. You harvest that along with the $7 million in savings just by being able to move back in, and that's just the capital savings.
That doesn't include savings associated with keeping the system full and our gathering and transportation going down. It really translates into significant value back to all of us.
Could you just follow up on that? The productivity uplift of that 15%-35% on the pads that you mentioned on the call, what do you think's driving that? Is that just more effective development as you complete more wells on a pad at one time? Is it improved lateral targeting versus when you drilled the initial laterals or something different?
I think a lot of it goes back to the good work of the folks there in Southpointe on their ability to do that technical work in the background. Yes, on the landing target. Even though we're at 1,000 producing wells today in the Marcellus, we're continuing to refine the approach on an ongoing basis. We continue to harvest data. We continue to look at ways that we can improve well results. Landing target is just one of those, and the other is completion design. We continue to tweak that approach as we move back into areas and we have greater learnings. Again, I'm going to reiterate this. When you have 1,000 wells, you have the benefit of a lot of data and the ability to really improve upon your results year-over-year.
Great. Then one last one, maybe for Mark on the divestitures. Have you sold anything yet this year to at least start that de-leveraging process?
Ron. Just after the quarter, we did close on the Mid-Continent asset sale. Proceeds of around $23 million. It was about $11 million of equivalent production. Modest asset sale, but that's the first step. We have active processes underway on more meaningful, larger potential divestitures. As we've said, we have good confidence that we'll be able to get a good announcement, a good deal completed by the end of this year.
In the announcement versus closing, it doesn't really matter from your standpoint, or does it, in terms of achieving that by December 31st, or if it's a sale in process?
Well, the announcement would just be made when there's a contractual arrangement, an obligation to disclose, and high confidence in closing the deal. As I said, these discussions are ongoing and progressing. We will announce it, and we are eager to announce it as soon as we are able.
Okay, great. Are we. Thank you.
Thanks.
Your next question is from the line of Bob Brackett with Bernstein Research.
Hi. I had a question on the lateral length. If I think of the cost of a horizontal well, there's the fixed component of that surface location and the vertical to get you down to target, and then there's that variable component as you go further and further out. Can you give a rough split on, say, a 10,000-foot well of those two buckets? That way, we can back into the capital gains as you go longer and longer.
Well, I think that maybe rather than try and break it down to that granularity, we just continue to see that if you look at the cost of Well, there's a lot that goes into it. I'll just say it this way. It can be varied on number of wells on the pad site. It can vary by where in the field we're going to drill that specific well sequence, whether it's dry, wet, or super-rich. Also, the efficiencies we see by area. Clearly not all Marcellus drill's the same. That's probably less easy to break down in a percentage basis. Again, as we look over the, let's just even say the 6 months of this year, we've seen our efficiencies continue to improve on the vertical section that you're pointing to, in addition to the horizontal section.
Clearly the top hole section is the cheaper of the equation. Yeah, we just continue to see on our cost per foot basis, we're decreasing on both sections of the hole.
If I try to get at it in a different way, if I contrast the cost per 1,000 foot of one of your dry wells against a super-rich, that number is sort of $650,000 versus $800,000. Should I take that incremental and say that's mostly completion intensity, or is that jewelry to handle the multi-phase flow?
Well, from an equipment and hardware standpoint, really from the surface down, there really isn't a lot of variability as we move across the field. You'll see, no doubt, some differences in the surface facility configuration, whether it's dehydration equipment or maybe something in the wet gas area where now you're dealing with more processable gas. As you move across the field, the drilling portion is about a third of the cost compared to the completion side, which is more around two-thirds of the cost.
Okay. Appreciate the insights.
Your next question is from the line of Holly Stewart with Scotiabank Howard Weil.
Good morning, gentlemen. Maybe the first for either Jeff or Dennis. You reiterated your 2018 production target of 11%. Can you remind us if you've talked about an exit rate for 2018, and then maybe some thoughts around how that would position your production expectations for 2019?
Well, at this point, Holly, we haven't talked about an exit rate for the year. We continue to remain focused on the 11% target. We've got a real clear line of sight on that as we look at both Q3 and Q4. Q4 is going to be an exciting quarter for us as we look at some new infrastructure that's going to come into service. We referenced it earlier in the call with the Harmon Creek processing plant. There's some compression that also comes into play that supports that. We're excited about some long laterals that are going to feed that ability to produce from the field there and fill our fourth quarter volumes in our growth profile 11%. 2019, I think it's early in the game plan for us to talk about 2019.
What we do know is that we're entering the phase of evaluating what kind of growth profile, and as Mark referenced, what that looks like within cash flow, and also factoring in North Louisiana results as well.
Okay. That's helpful. Maybe Dennis, just another one for you, it looks like in your deck, you've left the well cost pretty consistent. Is there anything you're seeing right now on the service side?
Yeah, good question. We continue to see what I would call is some very one-off small moves in price. Because of initiatives like we referenced on moving back to pads with existing production, we've really not only been able to stave any increases off, but the efficiencies along with it have been able to help us keep our costs flat. In some cases, we're still seeing cost reductions across the board when you look at our D&C costs. We have seen some small changes. They tend to be more like maybe a small increase in fuel or something very one-off and niche in nature versus the across-the-board service pressures that we may have seen in the past.
Okay, great. That's helpful. Then maybe just my last one for Mark. You're pretty heavily hedged on both the nat gas and crude side. Is there any kind of magnitude of free cash flow generation, I guess, ex asset sales that you can throw out there for 2018?
I think for 2018, as I said, we are targeting a capital program within cash flow. We are well hedged to your point, and we'll continue to follow that on a go-forward basis. We'll see good reduction in borrowings under revolver based on our expectations at current prices. I think following the trend of our targets of getting below three times in the near term is the objective, and accelerating down the asset sales to get closer to the long-term target of two times. We haven't provided an annual cash flow number, so I'm hesitant to throw out a specific free cash flow number. Just on a trend basis, where our pricing is, I think you can extrapolate some guidance there on what the leverage looks like in achieving our near-term targets.
Understood. Thanks, guys.
Thank you.
Your next question is from the line of Sameer Panjwani with Tudor, Pickering Holt.
Hey, guys. Good morning.
Good morning.
Good morning.
On Terryville, you highlighted in the prepared remarks you guys were seeing some faster cycle times and some lower operating costs. Are you guys changing anything down hole as you try to increase the competitiveness of that asset?
Well, good question. I would think the majority of the team's efforts has really just been a refinement over what we've learned over the past really 12-24 months through drilling across the core of Terryville. There's not a one initiative that we would point to other than just continual improvement, whether it's bit design or basically well plan and targeting. We've talked about, in prior calls, well placement being critical not only to well results, but also it's translating into our operational efficiencies as well. The team there in Houston continues to do a good job and also in Arcadia.
Okay, great. I know this may be tough to quantify, but how should we think about the upside or I guess downside to maintenance CapEx based on the capital efficiencies that you're capturing via longer laterals and other opportunities? Sounded like the numbers in your plan were fairly conservative.
I don't know that, like you said, we haven't quantified it yet to put it out to the market. But clearly, that five-year outlook, we tried to put together something we could meet or beat. So we made what we think are reasonable to conservative assumptions really across the board. Lateral lengths, we put in at 10,000 feet, not that that's our expectation, but that clearly we've been able to achieve that and do that. What you've seen for the last several years is lateral lengths continue to migrate longer. Ben has said we've actually stepped out with some really long laterals. So our expectation is that lateral lengths will increase with time, therefore, capital efficiency will get better with time, which should affect maintenance capital in a positive way.
Okay. Last one for me. In one of your responses to an earlier question, you highlighted having flexibility in 2019 and beyond in terms of using free cash flow to either get faster EBITDA growth or to accelerate debt paydown, both in terms of trying to right-size the leverage on your balance sheet. So how should we think about the factors that go into that decision of either growing faster or paying debt down faster?
I think the driving factors nearer term are to achieving the leverage targets as measured by debt to EBITDA. Getting below 3 times and then longer term, achieving something closer to 2 times. As we make the decision on appropriate reinvestment rates and what the resulting growth rates are over that five-year outlook, really, it's going to be driving factors behind shareholder returns. We will look at rates of return on wells, what then-current prices are. We'll look at what optimization of the existing gathering system and long-haul transport are, and we'll look at, quite frankly, what forms of returning capital to shareholders may make the most sense at that point in time. What are share prices? What are dividends at that point? What is free cash flow and what growth rates are being driven?
As you put all of those variables together, that will drive the overall size of the capital program and production. It will be kind of a continuous balancing equation, if you will, of those various factors over time.
You'd be willing to go slower than what your five-year plan would imply, depending on if you had better uses for that free cash flow than to reinvest it in terms of potentially putting it on the balance sheet earlier?
Yes. For example, if you can drive better cash flow per share by slowing down and deploying that cash flow in some other form or fashion, we would certainly consider that.
Okay. Thank you.
Your next question is on the line of Dan McSpirit with BMO Capital Markets.
Good morning, folks. Thanks for squeezing me in here. In last night's release, you spoke about a tailwind for capital efficiencies. How lasting are those gains in capital efficiency? What is the number for capital efficiency today based on your internal calc, and how is that expected to improve over time?
Yeah, I'll answer that, Dan. I think, when you look at year-over-year through the history of the program, we continue to see some advancement on a capital efficiency basis. I think we even sometimes surprise ourselves with the level that we've been able to achieve at the operating team and divisional level. What does that number look like as we project forward? Again, when you look at the five-year outlook, we've really taken a very conservative approach to what our capital efficiencies would look like. There's every reason to believe we'll continue to see the advancements that we've, as an example, been able to harvest in 2018. When you look at the 17,000 foot, 18,000 foot laterals as an example, we have every reason to believe that we can drill longer than that. We also know that to be successful, we've got to be repeatable.
All of that translates into, again, a $1 per foot drilling and completion cost per foot cost that's more efficient.
I think a couple other things to think about when considering Range that's not top of mind is really we have a really low decline rate. When you look at our corporate decline rate into 2019, we're projecting that to be below 20%, 19% or so corporate decline, which even for an Appalachian gas producer, I think is really a strong number, let alone for an oil producer. When you look at all in on a recycle ratio, I think we have one of the best recycle ratios in the business, regardless of basin or regardless of being an oil or gas producer.
Got it. Appreciate it. As a follow-up to a previous question on the asset sales, and appreciating that you can only say so much, but I'll give it a shot just the same. Who is in the market today to buy gas assets? That is, who are the likely buyers for the Northeast P.A. package or anything that's peeled off from Southwest P.A.? Just asking in an effort to better handicap the likelihood you can do what you say and need to do, and that's sell assets where proceeds go to balance sheet.
This is Mark. There's different pools of capital.
Dan.
Sorry, Dan. There are different pools of capital that are out there looking at different assets. You've got international buyers. You have your adjacent producers, strategics. You also have quite a few PE-backed companies, both existing and new teams with commitments looking to deploy and acquire their initial start-up assets. The dialogues that we are having and have had in various divestiture processes over the last 18 months have been quite thorough with those different pools of capital on the various assets. You're not dependent on one particular market. You have options and discussions with varied parties.
I think the quality of the asset is a key thing. Then I'll just circle back to the high-level thing, and I think different people have hinted at, for the reasons you all understand, that's all we can say at this point. Like Mark said, we look forward to sharing more when we're able to do so.
Okay. Got it. Appreciate that. Then, just lastly here, just quickly, has the Cotton Valley asset been fully scrubbed at this point? That is, what's the risk of the 150,000 net acres that remains going lower, being written down even further as it changes in prices?
Oh, yeah. We've looked at that pretty hard. I think we're confident that at year-end, the number will be plus or minus the 150,000 acres that Mark said.
Great. Appreciate the questions, or rather the answers, and have a great day. Thank you.
Thank you, Dan.
Thank you.
We are nearing the end of today's conference. We will go to Subash Chandra of Guggenheim for our final question.
Thanks. First question is: Is there a will or an ability to change your product mix at all of any magnitude in 2019 by shifting rigs to the condensate window or the more liquids-rich window?
Yeah, good question. We always provide, I'll say, a level of optionality at the planning level for us to be able to move really across the three areas that we have in Southwest Pennsylvania. At this point, you're going to see a pretty balanced mix, clearly. We always do provide some optionality, and clearly moving back into pad sites allows us to react quickly, maybe a little bit more so than when you have to start with grassroots well points. Again, as we start to look at the 2019 plan, our vision going forward, back to Mark's comments around looking at how our plan would be tied to cash flow, we absolutely could have some possibility. Just like we've demonstrated in prior years to increase, with some degree of reasonableness, our ability to drill in the liquids-rich area.
I'd just like to pile in a little bit on that answer and go back to some of my initial comments in my prepared remarks that I think a lot of people just think Appalachia is a gas play, the Marcellus is a gas play. It's important when you consider the liquids, the differentiated position Appalachia has in basin fractionation, control of purity products, access to international markets that doesn't exist in the other U.S. liquids plays. Then to take it a step further, that Range has a dominant position in the NGL part of the Marcellus. We have the optionality of wet or dry. Therefore, that's an advantage. Again, we're one of the largest top three NGL producers in the country.
Right. Got it. The next question is: With the revised guidance for gas diffs, NGL diffs, and GP&T costs, does that fully reflect normal operations Rover, normal operations Mariner East and Leach, et cetera? Is this sort of intermediate step and then as things fall into place later in three Q, should we expect another revision?
This is Mark. I would say this is probably transitional. You will see, hopefully, Rover come online perhaps late in the next quarter, but first full quarter would be Q4 based on that expected timing. I think once you have our entire portfolio of long-haul firm transport on, you might expect potential further improvement.
I guess improvement on the commodity realization and some offset on the GP&T side once Rover comes on?
Yes, exactly. As we've talked about a little bit before on the GP&T side, it will peak in the first full quarter after Rover comes online. You'll see it tick up a little bit. Our guidance for the third quarter is $1.38-$1.42 or so. It might peak, call it mid $1.40 range in the quarter after Rover comes online. Keeping in mind that is offset by better realizations, and also keep in mind that some of that trend is impacted by processing fees and some % of proceeds expenses associated with the NGLs, which likewise are receiving better prices. That's offsetting that increased expense.
Over the longer haul, like we've laid out in the five-year outlook, fully utilizing the existing system and further growth anticipated to be sold in-basin, incurring no additional transport, we believe that, call it at least 25% improvement in gathering, processing, and transport is achievable.
Right. Got it. Okay. Final one for me. Do you think maintenance capital change very much pro forma for asset sales?
Yeah. We can't, and we haven't given any specific guidance to asset sales. Again, I think when you look at our low decline rate, strong recycle ratio, all that type of thing, I think maintenance capital is going to be amongst the best in class out there.
Okay, great. Top of the hour. Thanks, guys.
Thank you.
Thank you.
Thank you. This concludes today's question and answer session. I would now like to turn the call back over to Mr. Ventura for his concluding remarks.
I just want to thank everybody for participating on the call this morning. Thank you.
Thank you for your participation in today's conference. You may disconnect at this time.