山脈資源 (RRC) 2017 Q2 法說會逐字稿

Welcome to the Range Resources Second Quarter 2017 Earnings Conference Call. This call is being recorded. (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 speakers' 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 of 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; Ray Walker, Chief Operating Officer; and Roger Manny, Chief Financial Officer.

Hopefully, you've had the chance to review the press release and updated investor presentation that we've posted on our website. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system.

Before we begin, let me also point out 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. In addition, we've posted supplemental tables on our website to assist in the calculation of these non-GAAP measures. The supplemental tables also provide calculated natural gas differentials for the upcoming quarter and detailed hedging information for all products.

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

Thank you, Laith, and thanks to everyone joining us on the call today.

The second quarter of 2017 was another quarter where Range successfully continued to execute on its long-term development plan across our deep inventory of high-quality assets. As you know, Range has built a concentrated 500,000-plus net acre position in Southwest Pennsylvania and now has a 200,000-plus net acre position in North Louisiana, both of which we believe are best-in-class assets for creating shareholder value. I want to begin by reviewing a few significant events from the quarter, and then discuss what we expect to see for the remainder of 2017.

During the quarter, we drilled on the east and west boundaries of our Southwest Marcellus position with great success. Both of these pads, that I'd like to think of as bookends, were significant in that the dry gas pad on the eastern edge is now our highest rate of dry gas pad on record, and our super-rich pad on the western edge is our highest rate condensate pad on record.

If you look back at our first quarter release from April, we also highlighted a pad drilled on the north side of our Washington County acreage position. Production from that pad has been stellar and after 100 days, it has significantly outperformed our wet type curve. Ray will discuss these results in more detail in a few minutes.

The bottom line is that these recent results highlight the quality of our Marcellus position and further confirmed that we have consistent results across our Southwest Marcellus acreage. Every company says that they have core acreage, however, we encourage people to pay close attention to EURs per thousand foot and cost per thousand foot when comparing quality.

To me, it's interesting and noteworthy that Range's Marcellus discovery well was completed in 2004 and even after more than a decade of drilling, we're still improving and setting new records in different portions of the field. We continue to drill longer laterals in an effort to optimize our development in Southwest Pennsylvania.

Importantly, our blocked up acreage position allows us to drill some of the longest laterals in the area. Our average lateral in Southwest Pennsylvania for the first half of 2017 was approximately 7,500 feet. We're projecting to increase that to over 9,500 feet for the second half of 2017 and should average even longer laterals as we get into 2018.

It's worth noting that there will be an optimal lateral length, where normalized EUR begins to crest and returns are maximized, but we've not found it yet. In fact, 2017 results to date suggest that some of our longest laterals are performing extremely well on an EUR per thousand foot basis, which Ray will discuss in more detail.

On the marketing side, our team has a first-mover advantage to plan and acquire a right-sized capacity with one of the lowest cost firm transport portfolios in the basin. Importantly, this portfolio takes our gas to good markets that we have incremental demand expected in the coming years. By year end, we should have access to additional natural gas transportation projects to take our production out of local Appalachian markets and direct it to the Midwest and Gulf Coast regions.

Rayne/Leech XPress, in their Southwest and Rover Phase 2, are all currently being constructed and hence, scheduled in-service dates before 2018. The combination of these projects and strengthening local pricing will be drivers of our expected improvement in natural gas differential for 2018.

We've also made progress in North Louisiana as we continue to change development activity towards a steadier cadence. Right off the bat, the team has done a tremendous job of driving down the cost to drill and complete wells, which has opened new economic locations. As discussed last quarter, we got off to a slow start in 2017 with our North Louisiana production. The results we've seen from the group of wells brought to sales in the first quarter were not up to par with our expectations, but we are looking forward to seeing the results in the third and fourth quarters from redesigned wells in Terryville.

We also expect to have new test results from the North Louisiana extension area, 2 additional horizontal wells offsetting Vernon Field to the East and West. In addition, we'll drill 2 vertical wells science test of the STACK pay potential of the eastern offset to Vernon Field. Well logs indicate resources of 400 Bcf per section and stacked pays with multiple targets. These vertical wells will help us build our future development plans.

In addition to extensive log and well test results, Range is acquiring considerable 3D seismic across some promising acreage that will help delineate and potentially expand the position. Included in the 2017 budget is approximately $16 million for 3D seismic covering the western portion of our position. As Range learned in the early stages of what has clearly been an extremely successful Marcellus development, which required several years, shortcutting the time line in science is not an option. Unlocking the resource potential across 220,000 net acres of STACK pay requires a certain amount of time and well repetitions in order to establish the most predictable economic development program.

Moving back to the corporate level. A key question for Range is how to develop our huge inventory given the ongoing commodity price uncertainty. For 2018, we'll be responsive to prices and set our spending at or near cash flow, including any asset sales. This should lead to annual year-over-year production growth of 10% to 20% over the next couple of years, depending on commodity prices. Given our peer-leading well cost and EURs per thousand foot of lateral basis on a relative basis, Range's growth per dollar spent should remain amongst the best in the industry. Longer term, our sizable inventory of high-quality locations provides Range the ability to grow at a significant rate for a long time, if economically warranted.

Also important, thinking long term is the benefit that Range has in having stacked horizons in both Appalachia and North Louisiana with the added optionality of drilling dry, wet or super-rich wells. And looking at where we'll set the growth throttle over time, we'll continually seek to balance operational efficiencies, balance sheet strength, acceleration of NAV and return of capital to shareholders. Over the long term, we expect to generate significant free cash flow for Range.

In closing, Range's long-term planning has taken the company from its discovery of the Marcellus 13 years ago through years of significant growth, while leasing and holding over 0.5 million acres in Appalachia with STACK pay potential. And not to be overlooked is the innovative nature of our marketing and mid-stream arrangements that this long-term outlook has generated.

This is reflected in the improvements we are seeing in year-over-year differentials in our corporate recycle ratio, both enhanced by our North Louisiana assets. I believe that Range has the size, the scale and the quality of inventory that is extremely difficult to match. We will continue to shape our long-term planning around both strategic assets seeking to create long-term shareholder value.

I'll now turn the call over to Ray to discuss our operations.

Thanks, Jeff. Production for the second quarter came in at 1.945 Bcf equivalent per day, exceeding our guidance of 1.93. Guidance for the third quarter is 1.97 Bcf equivalent per day, and for the fourth quarter, it's expected to be 2.17 Bcf equivalent per day, resulting in annual growth of 30%.

This is below our previous guidance of 33% to 35%, and there are 2 main drivers behind this change. First, as mentioned on the last earnings call, the performance of the North Louisiana wells in the first quarter was below our expectations. Using round numbers, the underperformance of these wells and the corresponding frac hits to offset production accounts for the loss of approximately $75 million a day for the year. By itself, this would explain a 5% difference in growth for 2017.

Despite the early North Louisiana setback, we were still expecting to hit our full-year guidance of 33% to 35% growth as our Marcellus wells have continued to perform well. In many cases, significantly above our average type curves. However, we've been hampered by delays in obtaining the necessary permits. Again, using round numbers, 6 pads representing 32 wells were delayed an average of 25 days per well. This represents 800 combined sales days and approximately $75 million a day of production for the year, coincidentally, very similar to the underperformance from North Louisiana. So we could have withstood some underperformance in the early North Louisiana production or we could have withstood some delays in Pennsylvania permitting, but the cumulative effect of both results in a reduction to our annual guidance.

Importantly, the Pennsylvania permitting issues have been resolved, and we do not expect any delays going forward. And we anticipate significantly better well results in North Louisiana for the second half of the year. I want to emphasize that we still expect to exit the year above 2.2 Bcf equivalent per day, which is in line with our plans when we started the year. This $200 million a day ramp of new production coming online during the fourth quarter, both in North Louisiana and in Appalachia, fits well with our anticipated incremental pipeline capacity, expected improving pricing differentials and set us up really well for 2018.

Looking at some of the operational highlights for the quarter. Let me start with Appalachia. We had 2 exceptional multi-well pads brought online in June. These pads happen to be on the eastern and western edges of our acreage position. These pads, in conjunction with 2 other pads that were announced over the last couple of quarters, on the northerly and southerly portions of our development, have essentially book ended our entire position. This highlights the high degree of confidence we have across our acreage.

In the super-rich portion of the field, on the western edge, we recently completed the 7-well pad with an average lateral length of 10,685 feet, with the longest lateral being 14,444 feet. The wells averaged 54 stages on a per well basis with 2,000 to 2,500 pounds per foot of proppant placed with optimized completion designs that I'll discuss in just a few minutes.

We're currently flowing 5 of the 7 wells under constrained conditions with 2 wells to be opened up later. The average IP per well is 29.1 million cubic feet equivalent per day or 4,843 barrels of oil equivalent per day being 73% liquids. We've achieved and maintained rates of over 5,000 barrels a day of condensate off the pad for 24 days, setting a pad and per well record for condensate production. During the first 2 weeks of production, average gas and condensate rates were more than 40% higher than the next best offset pad.

On the opposite side of the field, in our dry acreage, we recently brought online a 4-well pad with an average lateral length of 11,100 feet. 2 of the 4 wells have lateral lengths in excess of 15,000 feet with up to 78 frac stages per well. All 4 wells are now producing, with the pad currently flowing, 100 million a day. The average IP for these wells is 30 million a day per well, and the 30-day average IP is 26 million a day per well. These have proven to be some of our strongest dry gas Marcellus wells ever as we've been able to maintain 100 million a day flat for 40 days from that pad.

Moving to the north. The super-rich pad we talked about last quarter near the planned MarkWest Harmon Creek plant continues to perform well and is 65% above the type curve after approximately 3 months. A similar story exists in the wet area, where 23 wells have been drilled over the last 9 months. These wells averaged 10% above the type curve after 65 days. Included in those results is a 4-well pad on the southern edge of our position in the wet area that we announced a couple of quarters back that averaged 9,625-foot laterals with 46 stages and IPs at over 35 million cubic feet equivalent per day per well. Today, those 4 wells are forecasted to average over 4 Bcf equivalent per thousand foot of lateral.

These results are exciting, not just because they're some of our best performance to date, but also because they illustrate consistent performance enhancements. Our development plans and designs have been evolving since we discovered the Marcellus almost 13 years ago. And over the last few years, we've utilized technology such as real-time data streaming, advanced data visualization, machine learning and predictive analysis.

The performance of these new wells demonstrates early wins using this technology, identifying opportunities for improved well performance and returns through optimization of our completion designs, which involves changes like using different proppant loading for specific cases.

Spending just a minute on the technology. Our most recent evolution of this multi-disciplined process involves developing a software platform driven by machine learning. This tool is used to address one of the most significant challenges, the nonlinear, nonparametric and highly dimensional nature of predicting well performance. This platform that our team developed connects our engineering teams to a single source of data combined with interactive and predictive models.

This allows them to focus their time on improving the economic outcomes of our capital program. It makes it possible to evaluate field development decisions in almost real time. We believe these tools and the multi-discipline approach that we've developed represents a unique and competitive advantage for Range. While we haven't been very vocal about it, our teams have been working with machine learning and predictive analysis for years. And what's critically important is that it's truly driving improvements as demonstrated by recent well performance.

Going further, these examples clearly illustrate the quality of our low-risk long lateral inventory in Appalachia, across the dry, wet and super-rich areas. These types of improving results, when combined with going back onto existing pads with existing gathering and compression infrastructure, generate economics that are among the best in the business. I'll repeat again, we literally have thousands of these types of opportunities, and I still don't believe we've drilled our best well yet. Here we are, almost 13 years after the discovery and well performance is still getting better.

One big driver of capital efficiency is our lateral lengths. In the first half of the year, our lateral lengths averaged 7,500 feet, but in the second half of the year, we expect to link to be turned in line to exceed 9,500 feet. These longer laterals increase the cycle time slightly as we make the transition, but they really set us up well heading into 2018.

Continuing with what was reported during our first quarter conference call, the drilling team continues to drill longer laterals this year and has drilled 7 of the top 10 longest laterals since inception. Of the 7 laterals, 4 were drilled in the second quarter, averaging over 14,000 feet. Daily drill lateral footages have increased by 57% versus the second quarter of 2016, resulting in a 23% reduction in dollar per foot drilled.

This type of reduction in cost offset some of the increases we've seen in services and supplies. The completions team finished the second quarter completing 20% more stages than the same time period last year, while utilizing less than 3 frac crews. As drilling was able to successfully drill record lateral lengths for the division, the completions team has been successful in completing these longer wells safely while continuing to test new technologies and processes.

Shifting to North Louisiana. Our plan for the year remains consistent. Focusing on Terryville, while methodically testing and delineating the extension areas over time. In Terryville, we've made great strides in improving cost, while driving operational efficiencies, and we're continuing to delineate the STACK pay potential of the field.

As of the end of June, we have 23 additional wells expected to be online this year with most of that activity in November and December. This group of wells includes 12 Upper Red, 5 Lower Red and 3D Pink wells in Terryville. The other 3 wells will be in the expansion areas. This is all designed to better understand the full potential of the Lower Cotton Valley. By year end, we'll also have 3D coverage across some very promising area, south of Terryville, that will further assist in our delineation efforts.

Looking ahead, we expect the Terryville wells in the second half of '17 to perform significantly better than the wells turned to sales in the first half for a couple of good reasons. First, as mentioned on the last call, the initial batch of wells included many that had been sitting as ducks for quite some time. Over a year, in many cases, and probably for good reason. We look at these ducks on a cost forward basis and made the decision to go forward with the completion.

Second, because the majority of the ducks were in a concentrated development area, we experienced significant frac hits to offset production as we completed the wells. We discussed this on the last call. In experimenting with completion designs in order to help mitigate that interference, we made changes to fluid intensity. Essentially, we pumped the designed amount of proppant with significantly less fluid. With additional production history, it is now apparent that we understimulated the wells. Or more simply, the wells have had lower IPs with flatter declines, indicating a less-than-optimum stimulation.

On average, we used approximately 40% less fluid per foot, and the resulting production showed a similar percent of decrease from what was expected. Going forward, we're going back to using a typical Terryville-sized completion. We have confidence in this because of the 6 wells we turned to sales in the second quarter, which were made up of 3 Upper Reds and 3 Lower Reds. In these 6 wells, we pumped larger volumes, but not as large as the original completions as we were in the middle of analyzing the data and beginning to determine that frac volume and not proppant volume was the key. Early indications from these 6 wells show that the results will be better than the quarter 1 wells and closer to our expectations. Thus, going forward, we're headed back to larger frac volumes and better outcomes.

Again, we believe the wells coming online in the second half of the year should meet our expectations and compete with the Marcellus. We're bringing in a frac crew later this month, and the crew will run steady throughout the rest of the year. The first of these wells will likely come online in mid to late September. So we should have some very early results from the improved completion designs in our next earnings release and call. With over half the wells coming online in November and December, we expect a significant ramp in North Louisiana production in the fourth quarter, setting us up well going into 2018.

Switching to the extension areas. The exceptional work the team has done in reducing well costs has allowed us to do more work in and around the Vernon Field, which is south of Terryville. The 2 expansion wells previously announced, each located in separate Terryville-sized fault blocks, again, one to the east and one to the west of the Vernon Field, continued to perform and plans are underway to offset each well with another horizontal well, which has spud the first of those next month, expecting both wells to be online late this year.

Additionally, we have 2 vertical science wells in the extension areas designed to test multiple horizons individually. This allows us to determine reservoir and rock properties unique to each layer in order to identify the best lateral targets. With over 400 Bcf per square mile and up to 6 target intervals, the potential is large.

In closing, in North Louisiana, we've improved well cost, operational efficiencies, and we're gaining more understanding of the full potential of the assets. In the Marcellus, we're still continuing to improve returns through newer technologies, lower cost, longer laterals and improved well performance. We expect solid growth in the second half of this year setting us up well for 2018.

Now I'd like to turn the call over to Roger to discuss the financials.

Thank you, Ray. The big story this time last year was the dramatic production in unit cost and continued improvement in capital efficiency. These positive trends continued this year and for the second quarter of this year, are coupled with higher realized prices such that our quarterly cash flow has more than doubled from last year. Meanwhile, our DD&A rate and direct operating expense combined is now down to $1.04 in Mcfe. GAAP net income for the second quarter was $70 million. Net income adjusted for noncash and nonrecurring items to match analyst methodology was $16 million.

This quarter, like the first quarter of 2017, was profitable even before considering the earnings contribution from our hedge book. Second quarter cash flow was $194 million, a 108% increase over the second quarter of last year. Fully diluted cash flow per share for the quarter was $0.79, a 41% increase over last year's second quarter. Second quarter year-to-date cash flow totaled $452 million, a 135% increase over the same period last year. EBITDAX for the second quarter was $240 million. Year-to-date EBITDAX was $543 million. These figures are 86% and 106% higher, respectively, than the corresponding periods from last year.

Cash margin for the second quarter was $1.09 per Mcfe, 55% higher than the second quarter of last year, while our cash margin year-to-date is $1.28 in Mcfe, 74% higher than the first half of 2016. With 2 consecutive quarters of profitability and improving margins and cash flow over last year, Range is off to a great first half with the majority of annual production growth for the year and improved takeaway capacity still to come.

Looking at our second quarter 2017 expenses. All items were at or below guidance, except for exploration expense, which came in $1 million higher than guidance due to the timing of budgeted 2017 [size of the] expenditures. Expense guidance for the third quarter of 2017 may be found in the earnings release.

Committed liquidity under our bank credit facility is just under $800 million and our unhedged recycle ratio is approximately 2.5x. With the ability to replace each unit of reserves produced with 2.5 new ones out of existing cash flow, our liquidity is more than adequate for our current and anticipated pace of operations. And as Jeff mentioned, the drilling throttle can be adjusted in response to commodity prices, available cash flow and asset sale proceeds.

Range has continued to add hedges to its current hedge position and presently maintains price protection on over 75% of its anticipated 2017 natural gas production at a floor price of $3.23 in MMBtu. Also, approximately 65% of our 2017 oil and NGL production is hedged above current market. During the second quarter, additional 2017 to 2018 natural gas oil and NGL hedges were added, details of these hedge additions may be found in the earnings release and Range website.

I would also like to draw your attention to the other supplemental tables posted on the website, particularly Table 9, which provides an illustration of our estimated third quarter 2017 natural gas price differential, including basis hedges.

Lastly, as we're approaching the 1-year mark for the Memorial transaction, investors can expect to see us file soon with the SEC the documents required to publicly register the 144A exchange notes issued with the transaction last fall.

In summary, with another quarter of solid profitability accomplished and the outlook for the second half of 2017 pointing toward improved margins and a stronger growth, we are clearly seeing the benefits of our hard-fought effort to reduce our cost structure and improve our capital productivity flowing through our financial statements.

Jeff, back to you.

Operator, let's open it up for Q&A.

(Operator Instructions) Your first question is from Dan McSpirit of BMO Capital Markets.

Turning to the Cotton Valley. In light of recent results here, how cautious are you in changing or experimenting further with the completion technique? I'm asking in an effort here to get a better sense of the rate of change going forward and whether Range will show better results than what the prior operator delivered or even with the acquisition economics were based on. I guess put differently here, are the results expected later this year as good as it's going to get?

That's an interesting question, Dan. I hope not. We are pretty confident, really confident, in fact, that the wells are going to be a lot better in the second half. First of all, I think I discussed this in detail on the last call that you kind of group the wells that are happening in Terryville into 3 groups. First group was wells that we really didn't have the ability to change hardly anything. And then the second group were sort of in transition, where we might have changed the targeting of the well or something like that. And then finally, the third group is what, of course, we're all interested in is the Range wells. Range picks the location, we pick the target, we pick the spacing, we pick all the parameters around the well. Those wells really started with the 6 wells that came online in the second quarter. And we began working on what is the most important factor in the completion design that impacts production. And we are pretty confident that we've realized now that, that is volume of fracture. It's different than in a lot of the shale plays. Again, remember, this is really a tight sandstone. It's a whole different frac geometry, and it's a whole different world, essentially. So what we've learned is that frac volume is important. And as we were in the middle of determining that, we've made some significant steps in volume sizes through those 6 wells. And of course, 6 wells is not enough to be statistically significant yet. But we did see enough of a correlation there to be really confident going forward with our plans starting later this month that the completion designs going forward will perform a whole lot better.

I think another key thing to look back on the acquisition economics is prior to Range announcing the acquisition, those wells were costing 10-plus million dollars, $10 million or $11 million. When we mentioned it on our acquisition economics were based on $8.7 million drill and complete per well. We're at $7.4 million. So when you take the $7.4 million against the type curves we have in the book that we expect that we'll get for the rest of the year, you're looking at really strong economics that compete with the Marcellus. And we have confidence that's what we're going to see for the second half of the year.

Okay, great. And as a quick follow-up to that, you talked about spending your cash flow, including proceeds from an asset sale or asset sales. What could be divested to cover the difference between cash flow and capital spending? And maybe how much is needed next year to generate, say, 20% growth at $3 NYMEX pricing?

Yes. I mean, when you look at -- we have sold, as you know, a lot of non-core assets over the years, about $4 billion worth. So we still have assets in the Mid-continent that would be deemed noncore. You could -- one could make the case that the stuff we have in Northeast Pennsylvania, although it's high quality, isn't -- it's away from that core block east STACK pay position we have in the Southwest. So there's other assets we have that we could sell. It's early to put out 2018. So we have assets we could sell to fill the gap. Clearly, we've done that in the back -- in the past, and we'll be disciplined, but actively trying to do that. The other thing is we said last October, consensus at that time was $3.25. When we set for $3.25, we could grow at 20%. So obviously, if with every -- all else being equal, if prices are lower than the $3.25, then growth would be less than the 20%. But I don't have a specific number to give for you today, but that's currently what we're -- where we are.

And your next question comes from the line of Ron Mills of Johnson Rice & Company.

As it relates to 2018, you talked about further differential improvement from those 3 pipeline systems. This year, I think you've seen, kind of expect $0.10 to $0.15 improvement in differentials. Can we expect something similar next year? And how much, if any, of that would potentially be offset by higher transportation cost to get to those better markets?

Yes, I think that we're looking at significant improvements next year in the order of what you just stated. So net-net, when you look at the cost to get to the markets, we're still expecting the benefit of improvements in differentials with nat gas coming in again. So we're -- the story of continued improvement differentials we see for natural gas, I think we see for NGLs as well.

Okay. And Ray, for you on -- in the Marcellus or just Appalachian Basin in general. In addition to drilling longer laterals, you talked about the use of machine learning. What other changes has that learning resulted in, whether it's are you using non-geometric completions, are you using more proppant? Or -- what are some of the benefits that you're seeing from that machine learning?

Well, that's a good question, Ron. I mean, the ultimate benefit is well performance. And we're clearly seeing -- in a lot of the examples I just went through in my remarks, significant improvements above the type curves, our average type curves that we've got published. So to me, that's always the true measure is are we seeing it in well performance? And we are. It involves a lot of things. From well design, from the standpoint of what target it should be in. Although the Marcellus is 1 compact package of shale, if you want to think about it that way, there are different layers in it. And again, we talk about the super-rich, the wet and the dry area, but what this machine learning capability allows us to do is take this tremendous amount of data, whether it's geological, geophysical, lot properties, all of the completion histories and reservoir pressures and everything else that we can see there and look at this in multidimensional views. In other words, there's no bounds on the machine as to how many different things it can consider at one time. And so it allows us to take an approach to use all those things you mentioned, whether it's changing the perforation designs, cluster spacing, the proppant loading, the amount of fluid that we pump, exactly which target we put the lateral in. And it allows you to look at not just 1 well on a specific well basis, but it allows you to take your capital program and say, what's the best way to get the best return in well performance out of this amount of capital in this field with these sorts of parameters. And so it's been a really eye-opening experience for an old fat guy, like me, to see this. And our team and the technical ability that they have today to develop that. We hope to do the same thing in North Louisiana eventually, but it will take some time. Again, we've only had that property for less than 1 year now. And we're beginning to apply a lot of those technologies, but it's going to take a long time to build that model.

And then just to clarify. Did you say the recent 6 wells that you mentioned in Terryville, are those the first wells that you've done from soup to nuts in terms of Range drilling design, completion design, bringing online? And would there be any legacy Memorial wells left? Or you've -- or have you moved through that whole inventory?

Yes. I think we own it from this point forward, bottom line. I mean, those wells were pretty much Range wells. I mean, a couple of them, we may have used permits that MRD already had in hand or something like that. But I think that we would consider those our wells. But again, we were in the middle of determining the results of what we saw from the first quarter. And clearly, we made a mistake. We've made what we thought was a good decision at the time, but looking at the results, it didn't turn out like we hoped. But going forward, we think we've cracked the code. And again, we'll start seeing those results in a couple of months from now.

And your next question is from the line of Charles Robertson of Cowen and Company.

This is Adam Meyers stepping in for Charles Robertson. Just had a quick question on, obviously, given some of your peers and their pending merger, I was kind of interested in what your thoughts are regarding industry consolidation, really looking at how Range fits into the mix there, given kind of the current low price per reserve that Range appears to be trading at.

Well, you're talking about the EQT-Rice merger. I think when you think of it at a very high-level, fewer companies, I think, in the basin drilling is probably a positive thing. It's probably a more paced development, a more prudent and more rational development. So I think that's a good thing for the macro. In terms of Range and the price we're trading at, I think when you look at the quality of our assets, the wells that we're posting, the improvements in cash flow per share, I think we're on sale. So it's, I would say that it's low. You know that I'm saying our share price is a bargain, to be clear, $0.73. Our IR team was pointing that out last night. When you look at where we trade versus some of our peers and then you'd compare the quality of assets on an equivalent basis, it's -- yes, I think for investors that have a belief in gas markets long term, Range is a good place to be.

Yes, definitely makes sense. And then I guess for my follow-up, it seems investors are gaining more traction with this idea of maybe the Cabot business model of switching to kind of sustainable growth that returns cash to shareholders. Do you see Range moving to that business model long term? Is that something that you'd be -- that you'd see on the horizon?

Yes. I think when you look at us long term, we expect to generate significant free cash flow, as I've mentioned in my opening remarks. And with long term, when you look at that, we'll look at all the different things that you can do from working with the balance sheet to returning capital to shareholders. So we'll be looking at all those different options.

Your next question is from the line of Neal Dingmann of SunTrust.

For Roger, I think my -- probably for Ray, actually, my first question. Ray, can you just talk 2 things here? You mentioned about -- I think it was you that talked about sort of the constrained conditions, how you're running a number of your wells. Is that -- will you continue to do that, is that more just -- and I know I've talked to Jeff and you all about this, just sort of the natural practice? Or is this more about you don't want to have to overbuild the infrastructure and then have the well sort of settle down? I mean, certainly the wells are impressive. So I'm just wondering when you talked about this constrained condition, what is driving that? And how do you see that playing out going forward?

Yes. That's a good question, Neal. And it's a philosophy we've had for many, many years now. Basically, when you design production facilities and things like that, you could design them to hold -- to be able to produce the IP of the well, unconstrained. But I think if you did that, it would be very uneconomical because you would have facilities out there that you've paid for that would only be used for a month or 2 or maybe 3 at the best case. So what we choose to do is look at it from a project standpoint and the optimal economic approach of what is the best, when you're looking at the fact that we're going to do thousands of wells over the years, and we're going to build this infrastructure system. And again, our design from the early, early on, and it took us 10 years to probably get it in place was that we would have this existing infrastructure of pads and pipelines and compressor stations, water infrastructure and all of that, that would allow us to optimally develop the properties going forward at the lowest cost. And I think you see that in our cost structure quarter-after-quarter, how we're getting better, LOEs are getting better, all that. But what that does is you bring on some of these wells, especially as we drill longer laterals. And we're seeing these performance enhancements that we've talked about this morning. All of that means that the wells come on, and they're basically choked back for months at a time before you start seeing those declines. And we believe that's the best economic, lowest cost approach for developing those resources. We're going to take a very similar approach in North Louisiana. And we've talked about that, which is significantly different than what they were doing before.

Great. Good point. And then just moving over to Slide 10, where you talked about the quality of your North Louisiana acreage. Could you -- you hit this a little bit earlier. Can you talk about -- when you look -- think about the delineation, is even going down as far as the Jackson Parish, I mean, is most of that delineated? Or how do you anticipate your plan over the next couple of 2, 3 quarters, where you'll still have to delineate down in that southern area? Or maybe just talk about the delineation plan in general, if you could.

Well, the second half of the year is pretty well lined out. And like we've talked about, I think it was 23 wells that I mentioned in my prepared remarks. And I think it was 12 Upper Reds and 5 Lower Reds and 3D Pinks and then 3 more wells in the extension areas. Most of the focus this year still remains on Terryville. And I think going into 2018, that won't change. We're still looking at delineating the edges of Terryville. In other words, it's kind of taking tiers of wells south from the existing development. We see a lot of potential there. There's still potential for STACK pay and the infill potential inside Terryville. It's going to take us some time to build the reservoir models and determined that. So we'll be working on that also. And then, like Jeff mentioned and I talked about a little bit, the extension wells, we've had some pretty exciting results, early results but pretty exciting, to the east and west of Vernon Field. And so we're going to continue some work there with some additional offsets. We've got some science work going on the east side of Vernon Field to try to determine just how much potential is there and what's going to be the best way to develop that. One of the things we've learned in the Marcellus, in the STACK pay position that we have in Southwest Pennsylvania, that it takes years, and you need to be very thoughtful and strategic about how you develop and stack those laterals and what that program's going to look like. We're taking all of that learning. And we're, basically, going to take our time and be very strategic in the same way throughout that whole 220,000-acre position. So we have a big 3D that's going to be coming in later this year. That is going to open up a lot more of that extension area to the south of -- to Terryville. So all of that said, the primary focus is still going to be drilling development wells in and around Terryville. But we're still going to have a pretty steady program, pretty consistently but strategically, delineating that acreage around to the south. But I think it's going to take some time to do that because we are going to be very scientific, strategic and data-based and really develop some long-term plans around that.

Your next question is from the line of Bob Brackett of Bernstein Research.

Could you guys talk about the 25-day per well delay up in Pennsylvania and your comfort level that, that won't recur?

Sure, Bob. What happened is the DEP had some issues with staffing and different things and the permitting delays just kept getting longer and longer and longer. We have worked with the DEP, they have developed a solution, worked with us very well. We have permits in hand now for '17. We feel very confident going forward. They have done a wonderful job in working with us to solve that issue. So what that caused us to do throughout the year was to substitute and move different wells around. It wasn't the same plan as we had early in the year when we developed the forecast for production growth. And so you substitute some wells, you delay some wells, you move some wells around, add a couple of wells to a pad here and there. And it just changes timing. And again, that doesn't change the economics of the well. The capitals still get spent. The EUR doesn't change. In fact, the EURs are getting better just because we're using all the new technology. But what it does is when you take like one of the 4-well pad that we did on the east side, it was $100 million a day for 40 days, that's an outstanding well. I mean, we knew it was going to be a good well. But it's really great well, but it ended up online 3 or 4 months later than we expected. And so when you take a big pad like that and it's delayed 3 or 4 months, that just impacts your year's growth. And so here we are, with 5 months left in the year, you just can't make it up.

And when you think of the progress we've made, if you think back 2 or 3 years ago, that was kind of unheard of and now we have that pad. Actually, it initially came on at $100 million per day from 3 wells. Great economics. No change to any economic parameter, no change to capital and year spent, but you slide that like Ray said, 3 or 4 months, it makes a difference. And then you do that with the numbers Ray said, it's impactful. But we're excited we have those kind of pads. And we're -- in that situation going forward, it looks like it's solved.

Your next question is from the line of Mike Kelly of Seaport Global.

Jeff, you gave that 10% to 20% growth range earlier in the call. I'm just curious on the commodity price you envision on the bottom end of that range. I believe, last quarter, you laid out $60 oil, $3 gas world. You could be 20%-plus. What's the bottom end envisioned?

Well, if you look at the strip pricing for next year -- and I'm probably a week out, is it 290? Something like that, 280-something. First quarter is good. We have good hedges in there and we think when you look at the pricing for oil and for gas, when you look at the rig counts from where they are, I think the Appalachian rig count right now is around 60 actually, combined Marcellus. Utica, it hasn't been spiking up. And you look at the cash flow that's available for Permian players, call it, $49 barrel oil or $45 to $50 or something like that, cash flow will be down. So we think that strip historically is wrong. It probably will come up a little bit. And interestingly, if you look in the back of our book on Slide 66, it kind of has total macro Lower 48 oil production screaming up like everybody sees it. But when you look at the total gas position in U.S. x to Northeast, it's pretty flat. So if you look at the Northeast, that's constrained, up in far Northeastern Pennsylvania until Atlantic sunrise comes on. That's basically you're looking at probably middle of 2018 or before so. So we think the macro setting up, their pricing may be a little better. We said it, $3.25 gas last October about where consensus was, that we'd grow at 20%. Consensus today, I think it's $3.12 or $3.14, something like that. So growth maybe a little lower, and I'm not going to throw a specific number out, but we'll be in good shape, I think, with where gas is next year. Most likely, expectation is at $10 to $20 range.

Okay. And the lower end of 10%, is that something that you could achieve at $2.50 gas price? How should we think about the lower end?

Yes, I mean, $2.50 and I think the whole industry slows down dramatically at $2.50. We were -- you saw what the rig count did early part of 2016 as gas went to $2.50 and ultimately, broke $2 for a little bit. The other good part, I think, the industry is pretty sensitive. The message anymore is most of the operators are going to be living at or near cash flow. So I don't think you're going to see the big out spends. If prices dip down, we'll be sensitive to cash flow. I'm sure you have a model of range and you can model what that cash flow is. But we're going to be sensitive and set the throttle somewhere in that position. I think if gas goes to $2.50, you'll see the industry slow down dramatically. I don't think it will stay there that long.

Got it. Appreciate it. Just a quick one for Ray. Just if you -- second half of this year, if these 22 wells in the Terryville don't really pan out, you don't see the results that you're looking to see. I'm just curious how you could think about or how quickly you could pull capital away, potentially from the Terryville in 2018, maybe slow down there and shift that back toward Appalachia?

Well, I mean, it's a good point, Mike. I mean, of course, if we don't see the results, then yes, we're going to slow down and look at this a lot harder. We have a lot of confidence in what we're doing going forward. We've seen the data. We've looked at it, it seems like 1,000 different ways with 1,000 different experts. And so I feel very confident that the team has their arms around it. And that we're really confident going forward. But again, we're going to learn a lot in the third and fourth quarter. We should see some really improving results in North Louisiana. But we're also moving the needle forward in Marcellus. We continue to make better wells there. So I think we'll look at all that as we approach the budgeting time and the board approves the budget in December. And I think that's when we'll know kind of what the plans are for next year.

Your next question is from the line of Brian Singer of Goldman Sachs.

Range is often lumped into the higher-levered balance sheets camp, and there's always been the case that I think you've made in EBITDA growth will help to delever. What you highlighted in one of your slides that you have been active in asset sales in the past. How close are you to considering more meaningful asset sales, equity issuance or other ways to bring that leverage down further, particularly if the $3.25 doesn't materialize?

Yes, Brian. This is Roger. I'll comment on the leverage. Yes, and you're exactly right. With our windshield ratio, the recycle ratio at 2.5, even with a pretty dismal backward-dated strip, we're able to grow within cash flow at a respectable rate. So that gives us a lot of comfort. The rearview mirror ratio at 3x debt to EBITDAX, at this point in the cycle, we're comfortable with it but long term, we're not. We want to get that back down to historical levels. And as you know, the first lever we pull, when we want to do that is the asset sale lever and as Jeff said, $4 billion is what we've sold in the past. We've still got some attractive assets to sell, and it would be imprudent for me to comment on the likelihood or expectations of that effort. But that's clearly, the next stop on the waterfall for those proceeds. When you look at our debt structure, it's a very stable balance sheet. Our bondholders are obviously pleased with the paper, the spreads remained tight to our index. We trade tighter than a lot of our even higher-rated peers. S&P has us at BB+. Both agencies at stable outlook, which is all appropriate, given our low cost structure, our asset quality, the deep inventory we've got, the track record. So as I said, we're comfortable at this point in the cycle, but we're going to work hard to get that leverage down. I think when you look at the composition of the liability structure, one thing you'll notice and investors will notice is we're carrying over $900 million in floating rate bank debt right now, which we're real comfortable with because we've got a rock-solid borrowing base. I mean, no pun intended and ample liquidity for whatever we have planned. But we really like having pre-payable debt that we can pay down literally at a moment's notice with some asset sale proceeds or if we're blessed with a normal winter. So that's going to be -- the first place we go is to reduce that debt, and we're positioned to be able to do that with that revolver balance.

Great. And then my follow-up is, it's about your guidance for next year. You talked about the risk from an oil -- from a gas price perspective. What do you have baked in, in terms of Louisiana well performance, Marcellus well performance and pipeline take away out of -- and timing out of Appalachia? What are the risks around the volume guidance for reasons, one way or the other, for reasons other than gas price?

Well, I think when you look at, again, we'll have a lot of flexibility on where we allocate capital. As Ray said, the good part is you look at the big fourth quarter ramp, $200 million per day, it's timely. When you look at the pipes that are coming on that I mentioned in my notes, it's also timely that differentials tend to be improved up in Appalachia in the fourth and first quarter. So we'll have a nice ramp going into there. We have flexibility. By the time we get to the end of the year, we'll know a lot more about the Terryville wells. Like Ray said, we have confidence in those wells in the second half. And with expectations that we have, those economics will compete with the Marcellus. However you look at the Marcellus, we're drilling longer laterals and we're getting some spectacular wells. And we do think, the bases will improve up there for 2018, given the new pipes that are coming on and the fact that we think overall that those pipes won't fill rig count. And like I said, out there, it's currently around 60. We have commented in the past to fill those pipes, the industry would have to be, we think, somewhere around 120 to 130 rigs. And that would have been a few months ago. And I've heard other people say the rig count needs to be at least 90 to fill them by 2019. So I think Range is in good shape, and we have adequate flexibility. We talked, all along, one of the advantages of the acquisition was to be able to toggle capital either way. And I can sit here and build a case where with success in Terryville and success in the extension areas, you'd toggle more capital that way or with bases coming in, in the Marcellus and longer laterals, we'll toggle more capital to Appalachia. So we'll look at that very hard as we go into next year. But with the pipes we have, I think our team has done a good job of thinking through the flexibility. And a couple those pipes that I mentioned, for us, that we're expecting should be on and on in the fourth quarter, that's Rayne/Leach and Adair Southwest, Rover is scheduled to be on. But even if there's a slight delay, I think our team does a good job of thinking through the various outcomes and planning for contingencies.

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

I'd say thanks to everybody for participating on the call. If you have additional questions, please follow up with the IR team.

Thank you for participating in today's conference call. You may now disconnect.