Rodney L. Waller - Senior Vice President & Head-Investor Relations Jeffrey L. Ventura - Chairman, President & Chief Executive Officer Ray N. Walker - Chief Operating Officer & Executive Vice President Roger S. Manny - Chief Financial Officer & Executive Vice President Alan W. Farquharson - Senior VP-Reservoir Engineering & Economics Chad L.

Stephens - Senior Vice President-Corporate Development.

Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Bob Alan Brackett - Sanford C. Bernstein & Co. LLC David William Kistler - Simmons & Company International Dan E. McSpirit - BMO Capital Markets (United States) Ronald E. Mills - Johnson Rice & Co. LLC Paul Grigel - Macquarie Capital (USA), Inc.

Subash Chandra - Guggenheim Securities LLC.

Good morning, ladies and gentlemen. We apologize immensely for the delay for today's call. Thank you very much for standing by today. We want to welcome you today to the Range Resources Third Quarter 2015 Earnings Conference Call. This call is being recorded. All lines have been placed on mute to prevent any background noise.

Statements contained in 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. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir..

Thank you, operator. Good morning and welcome. Range reported results for the third quarter 2015 with record production, a continuing decrease in unit costs and some outstanding well results.

The order of our speakers on the call today are Jeff Ventura, Chairman, President and CEO; Ray Walker, Executive Vice President and Chief Operating Officer; and Roger Manny, Executive Vice President and Chief Finance Officer. Range did file our 10-Q with the SEC yesterday.

It should be available on your website under the Investors tag, or you can access it using the SEC's Edgar system.

In addition, we've posted on our website complemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins, unit costs per mcfe and the reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call today. Now let me turn it over to Jeff..

Thank you, Rodney. It will come as no surprise to anyone on this call when I say that the third quarter was difficult. In the commodity business you go through cycles.

Those of us who have seen a few of these cycles recall what they feel like, the difficult decisions that must be made, but ultimately the companies with the right assets and strategy will emerge better for it. The Range team has navigated these cycles before, and has designed the company to consistently create value for its shareholders over time.

You have all heard these tenets before, but they bear repeating when we distracted by minute-by-minute price updates. We believe value is created year after year by having a large position in the core of a low-cost play, a great team that consistently and safely executes the business plan and a strong simple balance sheet.

Going a little deeper into each of these points, first, Range has the largest position in the lowest-cost play in North America. There is also tremendous additional potential upside in form of the Utica, downspacing in the Marcellus, the Upper Devonian, extending laterals and having size and scale.

This resource has been captured and is largely held by production, which allows Range to be disciplined in its activity levels. Second, a team that consistently executes. For over a decade, the Range team has grown production at almost a 20% compound annual growth rate. This was accomplished despite periods of declining prices and high service cost.

This team pioneered the Marcellus and helped bring other technical innovations into the mainstream, for example, water recycling and reduced cluster spacing. Marketing has been another area of solid execution with a history of firsts, including our first in obtaining takeaway capacity and the upcoming exports of ethane and propane out of Marcus Hook.

I believe that you'll see more firsts from Range. Third, the balance sheet is a foundation that enables the company to execute its strategy. Range has prudently managed its balance sheet in a consistent manner for many years.

As an operating-strategy driven company, we focus first on rigorous capital allocation to be good stewards of our shareholders' money. That has focused Range on building one of the best drilling inventories in the business. It has also led us to shed noncore assets totaling north of $3 billion over the last 10 years.

Liquidity and financial flexibility are important, and we develop this just as we do our drilling inventory. We are well positioned, with a carefully structured bank credit facility with ample liquidity and a long-term debt portfolio with staggered maturities.

In addition, we continue to make progress on our noncore asset sales, and we expect to announce one or more asset sales and close them by the end of this year. We will use the proceeds to pay down debt, further strengthening our balance sheet.

Turning to the third quarter, another three months of strong operating performance drove 20% growth in production. A relentless focus on costs and efficiency yielded a 12% reduction in our unit costs over the prior-year quarter. This came against a continued backdrop of weak product prices, which more than offset lower costs.

The good news is that two of the projects which I mentioned last quarter should help with fourth quarter pricing netbacks. Spectra's Uniontown to Gas City project became fully operational on September 1. This transportation allows us to move about 170 million per day net from local M2 Appalachian Index to Midwest markets.

The net effect is it has increased our netback price by more than $1 on this volume, and we expect that we'll see a continued uplift of $0.75 to $1 for the fourth quarter. The other project I mentioned during our last quarterly call was Mariner East I. Our understanding is that Mariner East I will be fully operational by the end of this year.

When operational, this project should result in a significant uplift on our ethane and propane pricing netbacks. We are the only producer that has capacity on this project, and we have 40,000 barrels per day comprised of half ethane and half propane.

We expect a $90 million uplift in our net cash flow on an annualized basis when combing the net effects from Mariner East, Mariner West and ATEX. For 2016 we have projected bookends for capital spending of $550 million to $890 million. Both cases give us good growth within or near cash flow, depending on the price forecast used.

We believe that if you look at the capital we're spending in 2015 for the growth we're achieving, we have the most capital efficient growth on a corporate basis versus any of our peers in the Appalachian or in any other basin. We believe in 2016 our capital efficiency will also be at or near the top of the peers. I'll now turn the call over to Ray..

Thanks, Jeff. During the first three quarters of this year we've demonstrated capital discipline, we've increased operational efficiency, we've further lowered our cost structure and continued to meet our production targets while staying within our $870 million capital budget.

Third quarter production was better than expected at 1.445 Bcf equivalent per day, again largely driven by improved performance in the dry gas area of Southwest Pennsylvania, and we're still on track to deliver approximately 20% year-over-year production growth. Our Marcellus growth is forecasted to be 26% year over year.

With our reduced capital spending in the fourth quarter and Mariner East starting up later than originally planned, our fourth quarter production is expected to average about 1.42 Bcf equivalent per day.

Our latest communications with Sunoco indicate that the Mariner East startup should occur in the next month, with full commercial operations for propane and ethane by the end of the year. Thinking ahead about the bookends for next year's plan, we expect that our production growth profile in 2016 to be consistent with previous years.

Importantly, our 2016 exit rate being higher than this year's exit rate, again setting us up for growth in 2017. Our cost metrics are consistently improving on both an absolute and on a per-unit basis. Corporate LOE per mcfe for the quarter was down 21% as compared to last year, and G&A per mcfe is down 26%.

We've made additional progress in operating efficiencies and reducing capital costs. I'll start with some highlights from Southwest Pennsylvania, where most of our capital is being invested.

To give you an idea of just how much progress we've made in drilling cost, for the last two months, August and September, our average lateral length has increased by 38% over the average for 2014. Despite drilling 38% longer laterals, our drilling costs per well have actually declined by 10%.

We recently finished a five-well pad at 45% less cost per foot as compared to 2014. This was all accomplished by a combination of service cost reductions, the application of improved drilling technology and improved drilling efficiencies. On the completion side, we've achieved a 44% increase in frac stages per day as compared to last year.

Three recent pads totaling 427 frac stages achieved an average between 8 and 10 stages per day. Combined with service cost reductions, we've seen completion cost drop by more than 34% compared to this time last year. We believe that these efficiencies can continue to improve going forward. We also believe that this is not the case for everyone.

It's a distinct advantage for Range on two fronts, both on the capital efficiency side and the operational side. Today we have some of the best recoveries per foot of lateral combined with one of the lowest total well costs per foot of lateral generating some of the best economics in the Basin.

Of course this is largely driven by our team and our large scale, stacked pay and high quality acreage position in Southwest Pennsylvania. One of the most important factors in improving capital efficiency is drilling longer laterals.

Our average lateral length this year is about 6,000 feet, and we expect to see it closer to 7,000 feet next year and still growing longer after that. Most of our competitors in the Basin are already drilling long laterals and will not see the same gains in efficiency going forward.

Therefore, we see an advantage with our capital efficiency increasing steadily in the future as we go forward with longer and longer laterals. The other distinct advantage is our operating efficiency. For example, we know that we frac more stages per day and have less downtime on our completions than any operator in the Basin.

Service providers know this and benefit with better utilization rates when they're on one of our locations. This generates a win-win situation for both us and the service company, resulting in Range receiving some of the best pricing in the Basin while the service companies maintain their margins.

Importantly, we're also continuing to see outstanding well performance. Recently we brought online a new five-well pad in the dry area of Southwest Pennsylvania. The wells are producing under constrained conditions into a high-pressure gathering system, with an average initial sales rate per well of over 26 million a day.

The five wells averaged 8,200-foot laterals with 42 stages. I also want to emphasize that the total well cost, including facilities, was less than $900 per foot. Now that we have more production history, I would also like to update you on a five-well pad in the wet area that we reported on earlier this year.

The average initial sales rate of the five wells was 18 million cubic feet equivalent per day under constraint conditions and had 120-day average of 8.5 million a day. The average EUR per 1,000-foot for the five wells on the pad is 4 Bcf equivalent per 1,000-foot, and those wells averaged 5,700-foot laterals completed with 30 stages.

The total well cost for these wells, including facilities, was less than $1,000 per foot, again, emphasizing class leading costs with 4 bcfe per 1,000-foot, which is one of the best recoveries in the entire Basin. Again, the rock rules.

Both our dry and liquids rich wells in the Marcellus and Southwest Pennsylvania continue to deliver outstanding results and are a real testament to our operations and technical teams. As we continue to drill longer laterals, we expect to see even better performance.

Our first two Utica wells in Washington County, Pennsylvania are now producing into the new dry gas pipeline, and we're currently drilling the third well on a nearby pad, expected to complete that well early next year.

Our reservoir modeling for the first well, which is based on extensive reservoir measurements and production history, puts the EUR in the range of 15 Bcf from a 5,400-foot lateral with 32 stages. On a normalized basis that's approximately 2.8 Bcf per 1,000-foot of lateral and is in the top tier of Utica wells to date.

Again, looking at all the production data from across the entire Utica play, our first well appears to be in the top-10 performers on both an absolute and a per-1,000-foot basis. And the second well is better. Remember, the first two wells are opposing laterals off the same pad, but the completions were different.

The first well was completed with 400,000 pounds of proppant per stage, or approximately 2,400 pounds per foot. And the second well was completed with 500,000 pounds per stage, or a little over 3,000 pounds per foot.

Both wells incorporated 100 mesh sand and 30/50 ceramic proppant and were similar in reservoir pressure, as you would expect, being direct opposing offsets. On the second well, we also utilized the choke management program designed to manage the near well bore drawdown. The second well is currently flowing to sales at approximately 13 million a day.

It's been online a very short time, but early indications suggest it will be better than the first. It was a 5,200-foot lateral also completed with 32 stages. As we evaluate these two wells and continue to develop our reservoir modeling, we will let the data and the modeling guide us in optimizing the completion design for our third well.

The third well is AFE-ed, (15:10) for a total completed well cost of $15.9 million for a 6,500-foot lateral.

This includes facilities, diagnostics, additional science and new technology, mainly managed pressure drilling equipment, allowing us to keep drilling under the large pressure swings that have been seen by us and others in Southwest Pennsylvania.

We believe as time goes on and we get more of these wells under our belt that we'll see between 20% and 30% reductions in total well cost resulting from technology advancements and operational efficiencies combined with improving well performance. We have 400,000 net acres of what we believe is core dry Utica.

Early wells drilled by us and our offset competitors in Southwest Pennsylvania are promising, and certainly help to prove up and delineate the Range acreage position. But those five or so wells have only limited production history to date.

We plan to gather data from the offset activity combined with our wells, and while we focus on the Marcellus in the near term, just like the super rich, wet and dry Marcellus and Upper Devonian, our Utica play could be another complementary large-scale and low-risk option in our portfolio, with good economics for dry gas growth.

Activity in Northeast Pennsylvania and in our Midcontinent division slowed dramatically in the third quarter, and today both areas have finished their capital spend for the year. Our Fort Worth team, which now operates both areas, has done an excellent job of lowering costs and focusing on optimizing production and revenue.

Our Southern Appalachian team in Nora is also finished for the year with its capital spending. They're continuing to bring online some of the best coalbed methane wells we've seen in years.

In fact, over the past 30 years, four of the top-five wells are the new design, and 11 of the top-30 wells are wells that we have drilled and completed since taking over full operational control of the properties in 2014.

Utilizing the new high rate and larger size frac technique, the recent CBM wells are 75% better than their average offsets, with significantly better economics. And again, this area has some of the best gas pricing in the Eastern U.S. It's large scale, low risk and has very low declines.

Environmental protection, regulatory compliance, employee safety and having positive relationships in the communities where we live and work remain top priorities in our operations. In Southwest Pennsylvania, we had no reportable spills in the third quarter, and we'll work hard to repeat that success going forward.

Employee and management commitment to safety has resulted in Range having only one OSHA-recordable injury thus far in 2015 and zero hours of lost time in the last 21 months. We are really proud of all of our operating teams for working safely, protecting the environment and being good stewards in the communities where we live and work.

Now, over to Roger..

Thank you, Ray. Financially, the third quarter of 2015 was much like the second quarter, with significantly lower realized prices across all commodities set against significantly lower costs and consistent capital efficient growth.

Year-over-year production growth for the quarter was 20%, and all-in realized prices were down by 36% from the third quarter of last year. We continue to improve our already low cost structure by reducing cash unit costs by $0.23 from last year, a 12% decrease.

All of our individual unit cost categories were at or below guidance, with another quarter of most expense categories coming in below last year on an absolute dollar basis as well. Fourth quarter line item expense guidance may be found in the third quarter earnings press release.

Revenue from natural gas, oil and NGL sales, including cash settled derivatives, was $390 million for the third quarter, a $7 million increase from the second quarter of this year but $73 million below last year's third quarter.

EBITDAX for the third quarter was $209 million and third quarter cash flow was $169 million or $1.01 per fully diluted share. Year-to-date third quarter EBITDAX was $656 million and year-to-date cash flow totals $536 million.

Net loss on a GAAP basis for the third quarter was $301 million, driven primarily by $502 million of pre-tax proved property impairments from some of our legacy shallow gas areas in Northwest Pennsylvania and oil properties in Northern Oklahoma. The properties impaired are non-core assets.

Year to date, less than 3% of total company production came from these impaired assets. Non-GAAP earnings reflecting common analyst methodology, which removes many non-cash and nonrecurring items, was $5.5 million or $0.03 per fully diluted share.

Both non-GAAP earnings and cash flow per share for the quarter were higher than the second quarter and above analysts' consensus. NYMEX strip oil prices were 16.5% lower at September 30 than June 30, and strip gas prices were 10% lower.

The fact that revenue, cash flow, EBITDAX and adjusted earnings were all higher in the third quarter of this year than the second quarter speaks to the responsiveness of the company to the current industry environment through continued cost cutting and capital efficient growth.

Turning to the balance sheet, the most significant improvement completed during the third quarter was the redemption of our old 6.75% notes. Listeners may recall that we issued $750 million of 4.875% notes during the second quarter, effectively replacing our 6.75% notes, which were not callable until the third quarter.

Having used the bank credit facility to bridge the two transactions, we redeemed the 6.75% notes in August using the bank credit facility. The refinancing reduces our corporate weighted average bond interest rate by 42 basis points, generating just under $11 million of annual interest expense savings.

Also, the redemption of our 6.75% notes places our earliest bond maturity in the year 2021. We remain well hedged in 2016 with a floor gas price of $3.42 an Mcf on over half our anticipated 2016 gas production.

Hedging activity during the third quarter, summarized in the earnings release and Range website, consisted of several new oil hedges and some natural gas basis swaps. All in all, a challenging but solid quarter with higher revenue, production, cash flow and lower costs sequentially from the second quarter.

In the fourth quarter we look forward to continued year-over-year growth, cost focus and balance sheet improvement. Jeff, over to you..

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

Thank you, Mr. Ventura. The question-and-answer session will now begin. The first question comes today from Matt Portillo with TPH..

Good morning, guys..

Good morning..

Good morning..

Thank you very much for the color on your initial thoughts around the Utica. I was hoping to get potentially a little bit more around development plans on the asset. You've laid out an EUR for the first well and an updated well cost.

How do you think about incremental capital spend on the Utica heading into 2016 and 2017 versus the current Marcellus and how those two projects potentially compete for capital?.

the Marcellus; the Utica; the Upper Devonian; and every horizon up and down the wellbore. So what we know is we're encouraged by our first and second Utica wells, and the wells in and around us.

And we think, just like we've been saying for a long time, that the drycore, the best part of the drycore of the Utica, we believe, will be down in Southwest Pennsylvania. We hold a big chunk of it; a few other operators do too. But the good part for us is it's stacked on top – it's right below the Marcellus. So we're encouraged by the Utica.

We've drilled our two wells, as Ray said, we're drilling the third, and we'll complete it next year. When you look at our plan for next year, our focus is going to be really on the Marcellus. We think, with those three wells, coupled with the activity in and around us, it'll give us a really good handle on what the Utica ultimately is.

And we're encouraged by what it could be. But what we know is we have 10 years' worth of production history and thousands of wells that delineate, really, our position. So that's the low-risk piece.

And again, on slide 16, when you look at our Marcellus wells right now, the EURs per thousand-foot average for this year 2.5 to 3, and Ray said, our better pad is as high as 4 Bcf per thousand-foot. Coupled with costs that range down there, you're looking at about $900,000 to $1 million per thousand-foot.

Or maybe said a little more simply, our Marcellus wells down there are basically 17 to almost 18 Bcf wells that cost roughly $6 million. So we view it as a complementary development, and we can speak for Range, we're going to put our capital where we're getting the most, the best returns and the best capital efficiency, coupled with the lowest risk.

So we're excited and encouraged by what the Utica could be. But in the short run, you're going to see our focus be totally on the Marcellus. And we think with our wells and the other wells that'll be drilled in and around us, that'll help delineate our Utica position, but we won't be spending a lot of dollars on science.

We'll put them into the strong return Marcellus wells that we have. Kind of a long-winded answer, but hopefully, Matt, that addressed your question..

Thank you. I know that you have a short queue so I'll jump back in..

Okay..

The next question comes from Bob Brackett with Sanford Bernstein..

Can you give a little more color on noncore asset sales? What's noncore? Is there a preference for oil versus gas? How do you think about pricing that you might get for those assets?.

Okay. Great question, Bob. And I really look forward to sharing the details on the asset sales, and when we can. We feel, I feel and our team feels, very confident that we're going to get one or more of those done prior to the end of the year. It's interesting, when you look back, it's a consistent part of our strategy.

We've sold over $3 billion worth of noncore assets really over the last 10 years. Thinking about that another way, the remaining assets that we have are noncore are high quality. So we've seen a lot of interest in those assets that are high quality.

And basically, you can see us putting almost all of our capital into Pennsylvania and into the Marcellus. Therefore, we're not funding some of these high quality areas where some of our peers and competitors are showing a lot of interest.

But again, I really look forward to sharing the details on those when we can, and feel confident that we'll get one or more done prior to the end of the year..

Do you consider the Marcellus and the Utica core?.

Yeah. Clearly, the Marcellus is the engine. The Marcellus is what's driving our company. Again, we're looking at 17 Bcf wells for basically $6 million. That's about as good as it gets. And with our being a first mover and in essence "having discovered it or pioneered it" we have the cheapest transportation to some of the best markets.

Some of these new transportation deals, like we have Spectra Uniontown to Gas City, an uplift of $0.75 to $1 on a huge portion of that in the fourth quarter. Mariner East propane and ethane are on the verge of starting up in the next 30 days, and it'll be fully on by the end of the year. That'll be a big uplift in our netbacks owning both of those.

So clearly, we think that's core and strong. We have a big position. We have 1.6 million net acres of stack pay potential. That's clearly size and scale on what we believe is the highest quality play in North America.

Even though those other assets are by definition noncore for us, they're not competing for capital and are not competing for returns, they're good properties. And we're seeing a lot of interest. So it would be the areas outside of there..

Great. Thanks..

The next question is from Dave Kistler with Simmons & Co..

Morning, guys..

Good morning..

Good morning..

Real quickly on the Mariner East piece of the equation, can you talk a little bit about what's contributing to those delays? I know you've been informed by Sunoco that they'll have it fully operational by year end, but is it purely just timing of facility development, items like that? Or is there any regulatory issues? Just any kind of additional color you can give us there?.

Sure, Dave. It's a good question. I can give a little bit of color. In the original plan, the startup was going to be in July with full operations for ethane and propane being basically full up and running in the fourth quarter. Of course, that's certainly been delayed.

And again to repeat, they should have startup operations begin within the next 30 days, and we expect full operation to be basically right at the end of the year. And so that's sort of how we've got it in our plans going forward. I think I would characterize the delays as mainly construction.

There were some permitting issues, and so forth and so on, but as you get closer to the imminent time that it starts up, sort of the over under, gets a lot – it's a lot more clarity in that decision. So we feel very confident.

We, of course, we're in partnership and working with Eneos guys, the Chicago Bridge and Iron Works guys, we're almost in daily conversations with Sunoco. We've got people on the ground there. So we're very confident that things are going to begin commissioning and so forth in the next 30 days with, again, full operations right at the end of the year..

Okay. So just for clarification, you mentioned permitting.

Has all of that been completed at this point or are you still waiting for something there?.

Yes. All the permits are completed. At this point, it's literally just the last part of electrician work, and commissioning of new operating systems and things like that..

Perfect. I appreciate that clarification. And then just one on CapEx for the balance this year. I know you guys are only going to be bringing 18 wells to sale since you brought a larger amount in Q3.

How much or how many of those wells are yet to be drilled? Just trying to triangulate, because it's a pretty significant step-down in CapEx quarter over quarter to stay within that $870 million guidance?.

Yeah. Let me start by saying as strong as I can that I am absolutely confident we will be within our $870 million CapEx budget. I talk to the guys almost daily in the different operations. And like I said in my prepared remarks, clearly in Midcontinent, Northeast PA and in Nora we're finished. There's really not anything going on there.

In the Marcellus we started the year with 15 rigs. We're down to five. I think we'll be four or five for the next couple of months. We may drop an air rig or something like that, but we literally watch that to the penny today. So we are absolutely confident that we'll end up there.

And I think what they've laid out in the press release is exactly what we're going to bring online. That plan has been in place literally from the first and second quarter of the year. We went into it knowing that that's how it would turn out..

Great. I appreciate it..

And again, our production – let me add one more thing. Again, our production profile, we don't expect to be going forward from starting next year we expect the growth profile in 2016, wherever we end up in the bookends, will be pretty consistent with quarter-over-quarter growth, just like we've seen in previous years.

So we don't feel like we're sacrificing anything. The first quarter is going to be big. I think you're going to see us add a couple more frac crews in the first quarter, probably pick up a rig – all those things that we do every year when we start out a brand new budget year..

Okay. That's helpful. Just to that point, I guess, so you'd be leaning on those 50, 60 drilled, uncompleted wells to get Q1 production kind of up robustly versus the decline in Q4.

Is that the correct way to think about it?.

Well, I know there's been a lot of questions about the drilled and uncompleted inventory, and when you look at the well counts, maybe it looks like there's more or less going into a year. But the way we typically tend to think about it today is in number of frac stages coming online, essentially.

And if you look at the number of completed frac stages or yet-to-be-completed frac stages that we're going to bring online at any given time, it's about the same going in to 2016 as it was going into 2015. So there's not a lot of difference there, in our mind. And then going forward into 2017, I would expect it will be something very similar..

Okay. I appreciate that added color. Thank you, guys..

Thank you..

Thank you..

Our next question comes from Dan McSpirit with BMO Capital Markets. Please go ahead..

the 10% or 20% case? And where does leverage sit in either case, applying strict pricing and assuming no proceeds from the asset sales?.

Well, let me start the discussion and then I'll turn it over to Roger. In terms of capital budget for 2016, we have a process and we're going to continue with the process. We have a board meeting in December and we don't want to get ahead of the board. We'll present it to the board and typically we announce that in January.

But to specifically answer your question. If where pricing is today, we would tend to be on the low end. We have the, of the bookends, given what we see today. And before I turn it over to Roger, let me say, as I said earlier, I feel very confident that we will complete one or more asset sales prior to year-end.

But, Roger?.

Yeah. I think when you look forward, it all depends, obviously, on the points you've made, Dan. What are prices going to be and how much you're going to spend. And on the lower end of the bookends, you're really not overspending at all, if not underspending. So in that case, like I said, the EBITDAX is up third quarter versus second.

So if your EBITDAX is increasing, you're not overspending, then your leverage is improving, even without any asset sales. So if I look at the balance sheet; I don't lose any sleep over the balance sheet. It's in great shape.

As I mentioned, our earliest debt maturity is in 2021; we've got billions in liquidity Our interest coverage for third quarter is 6.1 times. So we're very pleased with the balance sheet. And again, you don't have to take my word for it. Both the rating agencies just ratified in the last two weeks Range's credit rating.

That's not the case for many other companies out there. And you look at where our bonds trade, very tight spread to treasuries. Our 2025s are trading below 400. That's kind of investment grade land. So we couldn't be happier with our current balance sheet and look forward to managing that leverage as we go forward..

And I would just add to it a little bit. When you look into the fourth quarter and first quarter specifically, in terms of netbacks, we think netbacks will get specifically significantly better, maybe on the order of 50% better. I think there's some numbers in the release you can look at or you can follow with the IR team for modeling.

That's a combination of new projects starting up for us that result in better netbacks in pricing on the natural gas side as well as seasonality.

Coupled with that we think with Mariner East being fully up and running, those real low propane quarters that we had, we've probably seen the low there as well with Mariner East enabling one, lower transportation costs and therefore better netbacks, but also the opportunity potentially for better pricing by having the optionality of either selling in the Northeast markets when they're good or being able to export in a much more efficient way..

Got it. Many thanks. Have a great day..

Thank you..

The next question is from Ron Mills with Johnson Rice..

Good morning. Ray, on the dry gas pad you highlighted the five wells that had a 4 Bcf per 1,000-foot. Those obviously were over 8,000-foot laterals.

Is that kind of the plan going forward compared to your type curve of 2.5 Bs per well? I'm just trying to get a sense as to, is that the new normal?.

Well, actually that five-well pad, Ron, was a wet area pad. I think I said that in my notes. I hope I did.

But there was a five-well dry pad that I talked about with the new IPs that we just brought online, and then the five-well pad that has a significant amount of history, because we talked about it almost a year ago when it came online, we're pretty confident in those EURs. It fit our modeling.

We've got lots of offset history and reservoir models built all around it. So we're very confident in that 4 Bcf. They were about 8,100-foot laterals I think or so. And to answer your question further, yes. We do expect to drill. The team is actively trying to drill longer and longer laterals as we go forward.

This year the average of the wells that we're putting to sales is about 6,000-foot all across the Marcellus. Clearly, there's some that are much, much longer. And clearly, there's some that are still shorter. But the average is 6,000 feet. Next year, we see that average approaching 7,000 feet.

And I do believe, in a couple of years past that, you'll see us averaging close to 8,000 feet, more than likely. And I do think that the super rich area of the wet and dry and then the dry Northeast PA, that we may – we'll zero in on what those optimal lateral lengths are.

But I do expect that they'll be different in different areas for a lot of different physical and reservoir reasons..

But it seems even on the 1,000 foot, you're right, I did misspeak.

But that 4 Bcf is versus almost 3Bs in the wet gas, that some of the changes you're making beyond lateral length is also on the efficiency side where it looks like the EURs per 1,000 foot are potentially biased higher as well?.

Oh yeah. Yeah. Agreed. I mean, in addition to drilling longer laterals, we're still optimizing our frac designs. We're still looking at what's the optimal landing target and the optimal spacing between the clusters of perforations. And, yeah, we're looking at all sorts of proppant size mixes and proppant types and different things that we're looking at.

So yes. You're exactly right. We do expect that our EUR per 1,000, you could be seeing increase somewhat. And we'll do that in a normal process that we do each year, and it's usually around the end of year where we update those economics.

And I don't know if Alan wants to – Alan's in here, who really runs that effort for us and he can say a few words about that..

Sure. Yeah. I think that, as Ray mentioned, our knowledge base continues to improve and that we're going to continue to see the efficiencies going forward. And that was kind of part of the whole thought process.

As you get into these plays, you continue to understand what you have going forward, and we continue to expect to see improved well performance as we finish up 2015 and get into 2016. A little bit early to say exactly what we're going to come up with, type curves for 2016. We'll obviously update everyone in February on that..

Great. Given the time, I'll let someone else jump in. Thanks, guys..

Thanks, Ron..

Thanks, Ron..

The next question is from Paul Grigel with Macquarie..

Hi. Good morning.

On 2016, realizing the budget process is still going on, but with the recent pullback in natural gas prices, how should we think about the focus on spending in the dry gas areas versus the wet gas versus Northeast, Southwest, North, just kind of across the Marcellus asset base?.

Yeah. This is Ray. Paul, that's a great question. And I think you'll see us proceed forward just like we always have. We have a very disciplined capital allocation process. And we look AFEs throughout the year on a real-time basis, every AFE above a couple hundred thousand bucks has to go through Roger, myself, and Jeff.

So we get to look and see what real-time is happening in the market, and with that we will have some flexibility to be able to adjust throughout the year, just like you've seen us do this year, from the original budget process to what we finally arrived at in January. You saw us change our capital allocation and begin to change our mix towards dry.

As it stands today, clearly our dry gas economics are still better, and you'll see us continue to push a little bit more that way. That does not mean we're walking away from the liquids, by any means, because the returns there are still good, and we do still need to build infrastructure and do the things that we're doing over there.

But I do think you'll see our mix move more towards dry going into 2016 also..

Okay. And then just shifting – a follow up on the Utica.

On the second well, is there any broad indication on how much higher that EUR may be than the first?.

Well, that's a great question. And let me preface it by saying this is all really early in the play. There's only, in Southwest Pennsylvania, about five or so wells that have any history at all. I think ours is, clearly, our first well is about nine months now.

The wells after that, I think about the longest well after that is maybe getting close to 90 days. And then after that, some of them haven't really even been to sales yet. And so this is really, really early on. But we feel pretty confident in our well. We've got nine months of production history.

We've built some very extensive reservoir modellings that have 3D information in the reservoir; they have 3D modelling of the fracs that we've performed on the well. We've done a lot of research and diagnostics.

When we look across the entire play, including the stuff in Ohio, it's one of the top 10 wells as it stands today on an absolute basis and on a per-thousand-foot basis. So we're really pleased with it. And all we can say today is the first well has about 60 days, and clearly, it's way too early to start talk about the second well.

I'm sorry, I may have said the first well; the first well has about nine months, the second well has about 60 days, and clearly it's too early to talk about an EUR for it. But we can say, with some confidence, that it is better than the first well. So clearly we're really pleased with our first two wells.

The offset wells, hats off to EQT and CNX, great wells. There's no question about it. But I think they're really, really early. And I think this play is going to need some more time. Our third well we'll complete sometime early next year and look at that. But this is a different kind of play; it's a Point Pleasant that we're really targeting.

It's a carbonate, it's not a shale. Clearly, the faults and the fracture networks play a role in this. So I think there's a lot yet to be determined about how this play develops.

And while it looks very promising to us, and we're excited that it can be a very complementary play, it's something that we can do – it's another lever we can push going down the road if we want to build some dry gas growth. But like Jeff said earlier, I think at this point we're going to sit back, we're going to watch these three wells.

We're going to watch the offset activity that's around us, because the other important thing that I didn't mention about the five wells in Pennsylvania is they basically ring our acreage. They outline our positions, which is really great. So we're going to sit back and watch all of that.

Then I think as we go into 2017, I think we'll have a much better idea of how we see that development plan going forward..

Okay. Great. Then just one quick question on the quoted well costs.

Does that include any science or is that just straight D&C cost?.

Yes. The $15.9 million for the third well includes facilities, which is very important. I think you need to be sure to be apples-to-apples when you're looking at those. It includes diagnostics. It's got a significant amount of diagnostics and science still in it.

And then, of course, it's got some new technology, namely, the biggest one is the managed pressure drilling equipment..

Great. Thank you..

Okay..

We are nearing the end of today's conference. We will go to Subash Chandra with Guggenheim Securities for our final question..

Thanks for fitting me in. The first question is on the NGL ex force (46:15). Just curious how you gauge a sentiment or an end user appetite from Europe.

And just on some headlines we've seen from one of your customers, Eneos, if you see this as cooperative or competitive in that they got shale leases, they hired Mitchell people and buying gas properties out there? If you see that as sort of a stepping stone to broader exports or something that might stunt exports over time?.

Well, yeah. Subash, this is Chad Stephens. Thanks for the question. So from Range's perspective, we think for our NGL prices, realized prices, and especially propane, we think the worst behind us. Mariner East gives us a lot of optionality. We can use seasonality on the East Coast, seasonality demand on the East Coast.

We can put the propane on the water and focus on best prices, whether it be into Europe, or Asia or South America.

We have a new – we'll talk about it, we'll have our IR team talk about it more – but we have a new contractual relationship with a global trader that has deep understandings of all the international markets and have relationships with Asian propane buyers and European propane buyers. They have a deep understanding of shipping and logistics.

We're real excited about that. It's something we just actually inked – the ink is not even dry on the agreements, but it will give us what you're talking about, understanding of the buyers on the demand side, whether it be in Europe or in Asia. So we're excited about Mariner East.

We're excited about this new relationship we have with this global trader..

That's good to know.

And a quick geology question here, so Utica versus Marcellus, I guess I get the producibility questions, carbonate versus something that's probably not, but from a Bcf per 1,000, I'm just trying to understand why the Utica, given the pressures and the organic content of the Utica source rock into the Point Pleasant, why just naturally wouldn't have more gas in place than the Marcellus?.

Well, I think – I'm not a geologist, let me start by qualifying that. I'm a frack guy. But if you look at our map on page 15 in the presentation, and we've got some maps further back in the presentation, and you look at gas in place, these maps have been out there for some time. There's a lot of penetrations. There's a lot of offset activity.

There's of course hundreds, and hundreds and hundreds of wells in Ohio that have all gone together to put this map. And I think it's pretty consistent against – through all of our peers and Southwest PA and in Ohio that everybody agrees with the map. About the best gas in place numbers that you see are around 100 Bcf.

Now there might be some isolated areas that are closer to 150 Bcf per square mile. If you look at the Marcellus, it's about the same, if not higher in some cases. So I think it is what it is. The rock rules. I don't know that being in carbonate versus a shale would have any bearing on how much gas in place it has.

It's going to be more things like total organic carbon content, victronite reflectants, and permeability, porosity and pressure plays a big role. Overburdened stresses determine how it drills and how it fracs. All of those things play big, big roles in how these wells produce and how they basically develop going forward.

So I think the Point Pleasant, which is what we're all targeting, is a carbonate. It is not a shale. In the shales, you tend to have some component of desorption of gas from the clays that are present there. Clearly, there may be a little bit of that in the Point Pleasant, but we're way, way early. We clearly don't understand it.

It does appear in the Point Pleasant that this data comes from core lab consortiums that were all participating in where we donate cores and then we all share in the analysis and the data. That the Point Pleasant does have some pressure-dependent perm challenges.

So that's why you're hearing about choke management programs and managing the near-wellbore pressure drawdowns and so forth. And I think every operator is handling that a little bit different. But I think, as time goes on, we'll all zero in on what the best way to approach that is and go forward.

But I think you still can't get past what Mother Nature put there, and the fact that the rock rules. And what we all know at this point is that Bcf per square mile is what it is. And I think how you go about getting that out is going to be the key going forward..

And let me weigh in as a reservoir engineer. And that's my background, coming up through petroleum engineering. The other thing that really is critical is long-term performance.

So what's important to me is the fact that the oldest Marcellus well now, come this fall, which is our well, will have 11 years' worth of history, or 11 years since the discovery, 10 years' worth of history, but on thousands of wells in the Marcellus. So you have a largely low-risk play.

So when we say we have wells in the Marcellus that are, if you look on page 11, that are 17, 17.6 Bs that cost $6 million, we have a high degree of confidence that's what it is. And those are strong numbers. The Utica may be great, time will tell.

But ultimately it's a long-term performance of not just one well or two wells or 10 wells, but across a large data set that dictates what the economics of the play will be..

Thank you very much..

Thank you..

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

We believe that we have the most capital-efficient growth, that we will have the most capital-efficient growth for 2015 and 2016 versus any of our Appalachian peers on a corporate basis.

Importantly, with our 1.6 million acres of stacked pay potential in the core of the Marcellus, Utica and Upper Devonian, we have the option to drill dry, wet gas or super rich acreage. Since about 900,000 net acres are dry and the rest is split between wet and super rich, in essence this gives us a portfolio within a portfolio.

Coupling this resource base with our capital discipline and diversified marketing arrangements, which gives us multiple options that our competitors do not have, Range is positioned to create value as we move forward into an expected better market that more effectively balances supply, demand and infrastructure capabilities.

Thanks for participating on the call. If you have additional questions, please follow up with our IR team..

Thank you very much, sir. Thank you for your participation in today's conference. You may disconnect at this time. Thank you..