山脈資源 (RRC) 2016 Q2 法說會逐字稿

Welcome to the Range Resources second-quarter 2016 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.

Additionally, nothing on this call will constitute an offer to buy or sell or solicitation of an offer to buy or sell any securities, or a solicitation of any vote or approval in connection with the previously-announced proposed business combination between Range and Memorial Resource Development Corp. After the speaker's remarks, there will be a question-and-answer period.

At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, Sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range's second-quarter earnings call. 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 a chance to review the press release and updated investor presentation that we posted on our website. We will be referencing some of the slides this morning. 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 will 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 and to provide more detail on both natural gas and NGL pricing.

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

Thank you, Laith. We remain very excited about our pending merger with Memorial, but since we don't expect to close the transaction until mid to late September, Ray and I will primarily focus our comments on the results, opportunities and plans for our Marcellus operations. In the next quarterly call, we expect to be able to talk more about our plans for the combined Company.

I'll begin by reviewing what Range accomplished during the second quarter, then I'll discuss some of the key attributes we have that set us up for continued success. Range's ability to consistently drill low-cost, high-return wells across our acreage in the Marcellus, as well as focus on driving down unit costs, resulting in strong operating results for the quarter. Comparing unit costs realized during the quarter to this time last year, Range's LOE is down 44%, G&A is down 23%, interest expense down 17%, and DDMA was $0.95 in the second quarter, down 22% year-over-year.

We continue to achieve operational improvements in the Marcellus and our wells continued to exhibit strong performance. Ray will discuss this in greater detail.

All three of our liquids projects are now fully operational, and we have the ability to move ethane to Europe, Canada, and the Gulf Coast. We have the flexibility to export propane from markets hooked to anywhere in the world, or to sell into the Northeast markets whenever it is advantageous to do so.

All of the gas pipelines we're contracted on are either online or on schedule, including Spectra's Gold Coast expansion in the fourth quarter of 2016; Columbia's Rain Leach Xpress in third-quarter of 2017; and Rover Phase II in the fourth quarter of 2017. By the end of this year, approximately 70% of our natural gas is projected to be sold in markets outside of the Appalachian basin, further improving our expected natural gas differentials going forward. By year-end 2017, we expect over 80% of our production to be sold in markets outside of the Appalachian basin.

Gas pricing remained challenged during the second quarter, but pricing has improved since. And there are signs that later this year and into 2017, supply and demand will be more balanced, and pricing could significantly improve. We expect natural gas production in the US to continue declining for the remainder of this year. In Appalachia, there are only about 30 rigs drilling for natural gas in the Marcellus and Utica formations, with the rigs about equally divided between the two plays.

We estimate that it would take approximately 50 rigs to hold production flat in the Marcellus and Utica. An estimate to put 20 additional rigs back to work, including all associated costs to put the wells online, would result in an additional $4 billion of capital per year. It's also important to note that the drill uncompleted well inventory in the Marcellus and Utica combined continues to decline, and appears to be down about 34% in 2016.

The rig counts in all of the other US gas basins are at historic lows, and productions in these basins is declining. In addition, total associated gas from the oil plays continues to decline on a monthly basis since December 2014, and is down over 5% year-to-date. This supply decline is happening while demand for natural gas is increasing, primarily driven by Mexican exports, power generation, and LNG exports.

Looking into 2017, the Nymex strip has moved above $3.00 and we believe it can continue to climb. There's also a brighter outlook for ethane and propane for 2017. At Range, if these prices increases occur, we have the ability to ramp activity with increased cash flow. We have 231 existing pads that we can go back onto to drill additional wells, which increases capital efficiency and decreases the cycle time to ramp up.

Given our large footprint in Southwest Pennsylvania, we also have the ability to shift capital to drill in the dry, wet or super-rich areas. We are permitting wells across all areas, and have the ability to allocate capital on a real-time basis to the highest return assets based on current market conditions. To the extent there is available space in a portion of the gathering system, we'll direct drilling there, which will reduce our gathering costs.

We are pleased to report that the merger with Memorial is moving along well, and we currently expect to close in mid-September. As we said when the deal was announced, we believe that combining two of the highest quality North American natural gas and NGL assets will create a premier domestic natural gas company with a resilient and flexible platform for sustained growth. We believe that Range's Marcellus and Memorial's Lower Cotton Valley are the two lowest-cost gas plays in the United States, and are strategically located near key demand centers.

The combination creates a unique portfolio with more optionality for Range and an enhanced ability to serve our end customers. The product mix in both assets are similar, which enables us to utilize our marketing expertise for both natural gas and NGLs, and leverage our existing customer and transport relationships to find innovative sales arrangements, just as we've done in the past. Perfect examples include our relationships and agreements to sell ethane to Nova Chemicals in INEOS, as well as our marketing of international propane.

On the technical side, we continue to improve the economics of the Marcellus, and have identified transferable ideas that can enhance the economics of the Lower Cotton Valley, resulting in improved capital efficiency and returns. Lastly, the merger will benefit from the existing Range corporate infrastructure, procurement and other expertise, which is expected to achieve lower unit costs, enhance profitability throughout the commodity price cycles, and result in a better, stronger company.

In summary, we believe the combined entity offers investors five key positive attributes. The first is a very high-quality, low-cost asset base in two complementary basins. The second is improved capital efficiency, as illustrated by the opportunity to go back onto existing pads to drill new wells in the Marcellus and to drill highly prolific wells in the Lower Cotton Valley. Continuing to drill longer laterals and optimizing landing and targeting will also drive improved capital efficiency in both regions.

The third key attribute is top-flight operational execution, as evidenced by consistent track record of operational achievements. The fourth is a strong marketing effort, highlighted by Range's ability to move ethane and propane to multiple domestic and international markets, and to move natural gas to multiple markets within the US, with over 80% of our Marcellus gas moving to markets outside the Appalachian basin by the end of 2017.

Finally, the combined Company will have an even stronger balance sheet with ample liquidity and a strong hedge position for 2016 and 2017. All of these attributes position Range to deliver strong operating results and build sustainable long-term shareholder value.

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

Thanks, Jeff. We continued to execute our strategy with notable success. We're focused on improving well performance, prudently allocating capital to our highest-quality properties, improving capital efficiency, and continuing to drive down costs in all categories.

Production for the second quarter came in at 1.421 Bcf equivalent per day, with 36% liquids. And for the third quarter, we're setting guidance at 1.43 Bcf equivalent per day with similar liquids. Our annual guidance remains at the high end, the 1.41 to 1.42 Bcf equivalent per day, which would represent growth of approximately 10% over last year. And we're still forecasting sequential quarterly growth, with our exit rate being higher than it was at the end of 2015, which sets us up well for growth in 2017.

We continued to drive down our overall unit cost in the second quarter, resulting in an 8% reduction from the prior-year quarter. As Jeff mentioned earlier, all of the categories were better than expected, but I believe they are worth mentioning again. Our operating teams continue to work more efficiently, and our LOE per Mcfe is 44% lower than a year ago and 21% lower than the prior quarter.

G&A was down 23% and DD&A was down 22% year-over-year. All these are examples of our teams driving down costs and increasing efficiencies while working safely, with a focus on environmental responsibility.

Driving a lot of our LOE improvements is the handling of water. Remember, Range was the Company that introduced the reuse of flow-back and produced water, and the first company to achieve 100% reuse back in 2009. With some very creative and innovative thinking, our team will save over $18 million in water handling this year, impacting the CapEx ledger, while also lowering LOE costs.

This savings is driven primarily by three things: first, improved completion designs, meaning a greater focus on proppant placement and conductivity rather than water volume. Second, a steady and highly efficient frack program, allowing us to work cooperatively with many operators in the area that supply reuse water to our sites at no cost to Range, thereby greatly reducing our costs.

And third, we've been able to really focus on our infrastructure and water handling logistics, therefore developing advantages that are very unique to our operations in Southwest Pennsylvania. Minimizing our costs for handling water is a huge advantage, and not having a water MLP that we would have to feed, allows us to focus on the true bottom-line costs.

Capital efficiency continues to improve, and I'll go through just a few examples from our operations in Southwest Pennsylvania. On the completions front, we completed 1,067 stages. This is a 23% improvement over the second quarter of last year, with the same number of frack crews as we had last year. We've reduced the total average completion cost per foot of lateral by 25% compared to last year.

Our top four pads completed in 2016 have averaged over 8.3 stages a day for a total of 173 stages. The best pad achieved a completion cost per foot of almost 15% below the average, which again, was already 25% lower than last year. We're forecasting a 23% reduction in CapEx for production facilities, resulting in almost $9 million in savings this year as a result of design improvements, reductions in labor and materials, and redeployment of existing equipment.

On the drilling side, we achieved a 27% reduction in drilling cost per foot compared to last year, while drilling 6% more lateral feet in the quarter. The laterals drilled during the second quarter were 8% longer than last year, and seven out of our top 10 days for lateral feet drilled in a day were in the first half of 2016. This illustrates that we're still improving and expect to continue.

Our best well drilled this quarter, and our fastest well to date, was an 8,634 foot lateral drilled at a cost that was 38% lower than our average -- again, with our average during the quarter being 27% lower than last year. As we've covered many times in the past, we believe our average total well cost per foot, including facilities, are the best in the Southwest portion of the basin.

We believe, if you look at some of our recent achievements -- which are clearly more than just a few wells -- you will begin to appreciate the improving capital efficiencies that we expect to see going forward. This, combined with the ability to go back on existing pads and infrastructure, as well as with drilling longer laterals, suggests we can build significant value going forward. Again, all of this is being done safely and in an environmentally-sound manner by a strong operations and technical team, and by all our folks across the Company.

Today we can drill a 9,000 foot lateral and complete it with 45 stages averaging 2,000 pounds of proppant per foot of lateral in our wet area with full facilities on a brand-new four-well pad for approximately $7.7 million per well. If we did so on an existing pad, the well costs could be as low as $7 million a well.

In comparison to our peers, our cost is less -- over $1 million less on an apples-to-apples basis. And our well performance is better, resulting in better economics than any of our peers in the Southwest portion of the basin.

I should point out that this is not just theoretical. We have many of these types of longer lateral wells planned for the future. For example, we plan to drill a seven-well pad in our super-rich area later this year, averaging approximately 10,700 foot laterals with the longest at 14,500 feet. These wells will be completed early next year, and we look forward to sharing the results of these, and other long lateral pads, in the future.

We continue to achieve outstanding well performance. I'd like to take a few minutes to walk you through some of our recent top-performing wells.

We recently completed a seven-well pad, averaging 5,717 foot laterals and 30 stages in a super-rich area near the end of the first quarter and into the beginning of the second quarter. The average 24-hour rate to sales under constrained conditions was 20.6 million cubic feet equivalent per day, or 3,434 barrels of oil equivalent per day, since it was 73% liquids.

In the wet area, our top pad was a three-well pad, averaging 6,782 foot laterals with 35 stages. The initial 24-hour rates of sales under constrained conditions was 27.7 million cubic feet equivalent per day. And in our dry area of Southwest Pennsylvania, our top pad was a five-well pad, averaging 7,424 foot laterals with 38 stages per well, and the initial 24 hour rates of sales -- again, under constrained conditions -- was 26.7 million cubic feet a day.

I'd also like to review some of the best wells we've drilled on a normalized EUR per 1,000 foot of lateral basis. All of these wells have been turned to sales within the last nine months.

Let me start with the dry area in Washington County. This is the five-well pad that I mentioned earlier, that was brought online in April of 2016, averaging 7,424 foot laterals. This pad is in the same area as the pad in the presentation on page 42, where we went back on the pad and drilled additional wells.

This five-well pad is similar in recoveries to that pad at over 3 Bcf per 1,000 foot, or over 22 Bcf per well. And the wells are projected to cost approximately $5.3 million each. Again, all these well costs that I refer to include all of the facilities. Similar to the pad in the presentation, we can go back to this pad and drill additional top-tier wells along with wells on offsetting pads in the future.

In the wet area, we turned a four-well pad, averaging 6,964 foot laterals, to sales in the fourth quarter of 2015. This pad is in a similar area as the wet area pad in the presentation on page 41, where we went back and drilled additional wells. This four-well pad is projected to average 4 Bcf equivalent per 1,000 feet, or approximately 28 Bcf equivalent per well. Wells like these in this area would be projected to cost approximately $5.8 million today.

In the super-rich area, we brought online two pads with 10 wells in the first quarter, with an average lateral length of 5,100 feet. These wells are currently projected to average approximately 2.8 Bcf equivalent per 1,000 foot or 14 Bcf equivalent per well, costing $4.8 million.

On the last couple of calls, we've discussed the unique advantage we have due to our expansive inventory of existing pads and infrastructure, which allows us to drill wells at much lower cost, thereby significantly increasing capital efficiencies. Today, I'd like to touch on another advantage.

Currently, we have an inventory of over 230 pads that we could eventually utilize. This is comprised of new pads, pads that are in various stages of execution, 124 producing pads with five or fewer wells, and 59 producing pads with six to nine wells. All of these represent opportunities to drill more laterals. We can go back onto the pads as needed, when there's room in the gathering system and the infrastructure would be ready.

We have in-hand today all the permits necessary to drill 42 laterals on those pads, if desired. This is critical when you consider our ability to quickly ramp up activity in volumes at much less cost than others that don't have a deep acreage and existing pad inventory.

Considering Pennsylvania as a cycle time for a grassroots, multi-well pad and all the permitting that goes with it, civil engineering, environmental permitting, and title can take a long time. On the execution front, from the start of the pad and road construction, to turned in line, is around nine months for a four-well pad.

For wells on an existing pad with permits in-hand, that cycle time can be less than half that, depending on the number of wells. We believe this represents one of our greatest advantages, and well-positions us for future growth. And we believe it allows us to allocate our capital towards projects that will come online to sales in short order.

While our 2017 plans are still under development, the important things to consider are that we have a large core and high-quality position; our acreage is largely held by production; a low cost structure; strong capital efficiency; we're drilling longer laterals; we have an attractive, low-cost transportation portfolio; the ability to drill on existing pads as well as new pads; permits in-hand to quickly and efficiently grow when the time is right; the flexibility of drilling in dry or liquids-rich areas; a low decline base production corporately of 19%; very low maintenance CapEx; and finally, strong operations and technical teams with a proven track record.

Most importantly, we will continue to allow capital -- allocate capital to our highest-return projects across our large core, diverse and stacked pay portfolio, as we develop plans for 2017 and beyond.

Switching to marketing for a few minutes -- year-to-date, local Appalachia basis remains challenged. The good news is we have a portfolio of low-cost takeaway capacity to markets that improve our price realizations. Later this year, during the fourth quarter, we will add to our portfolio $150 million a day of firm capacity on the Spectra Gulf Markets project at a very reasonable transport fee.

Additionally, we anticipate the Columbia Leach Rain Xpress project to be in service by the end of 2017, which adds an additional 300 million a day in capacity. Both of these projects move our gas away from Appalachia to better prices in the Gulf Coast, where demand is projected to dramatically increase over the next several years. As Jeff mentioned in his comments, once the Gulf Markets project is in service, approximately 70% of our natural gas production is projected to be sold outside the Appalachian basin.

Once Leach Rain Xpress is in service, over 80% of our natural gas will be sold outside the basin. We recently signed new condensate sales agreements, which will improve our price by several dollars per barrel over first-half realized prices. On the NGL side, Mariner East began officially flowing ethane and propane to Marcus Hook on May the 1st. INEOS is loading their state-of-the-art Dragon class ships with ethane, and transporting it to Europe. And Range is marketing propane globally out of Marcus Hook, and realizing prices above Mont Belvieu.

These liquids marketing arrangements have significantly improved our NGL realizations compared to last summer, as reflected in our price realization improving to 24% of WTI compared to 14% of the WTI last year. We also wanted to provide a brief update on our third Utica well, the DMC 10H, for which we are currently in the process of conducting a production flow test.

The test is part of a larger technical evaluation to characterize the reservoir and help crack the code on this play. It's still very early in the producing lifecycle for this well, but it continues to produce with a flowing pressure and rate within the top four wells in the Utica, which is consistent with what we reported at the end of the first quarter.

As I've said in the past, the Utica costs almost 2.5 times more than our dry Marcellus. And while the Utica represents tremendous future resource potential, even with anticipated efficiencies, the returns from our Marcellus wells currently exceed Utica returns. Given limited production history thus far, on a risk-adjusted basis, it's clear to us that our high-quality Marcellus wells are currently the superior investment.

Our Utica potential is held by our Marcellus development. And over time, we expect that the Utica can be a complementary development opportunity. But for now, our plan is to monitor our three wells, along with offset wells, while continuing to build our reservoir models, and then determine the path forward from there.

In the meantime, we will remain focused on our high-graded Marcellus core acreage with the best economics possible. As we continue to lower cost, improve efficiencies, drill longer laterals, and develop our stacked pay core assets, we remain well-positioned to create sustainable, long-term value.

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

Thank you, Ray. The biggest second-quarter story on the finance side is the dramatic decrease in unit cost, led by a 44% year-over-year reduction in our water handling and processing cost, which is largely responsible for the record low $0.15 per Mcfe cash direct operating expense. We also saw meaningful reductions in contract pumping, wellhead treatment costs, and utilities.

While not all of these cost reductions will be recurring -- such as those attributable to the mild weather -- the relentless focus on cost, and the benefit of having shed significant non-core assets over the past year, have moved our already-low-cost structure even lower. Aggregate unit costs were down by 8%, or $0.24 per Mcfe, from the second quarter of last year. Third-quarter expense guidance, found in the earnings release, reflects our current view, which includes a significant drop in unit costs from prior guidance.

It's amazing to note that six years ago in 2009, our DD&A rate per Mcfe, and direct operating expense combined, was $3.16 per Mcfe. The next year, 2010, was the first year that the combined cost fell below $3.00 per Mcfe. And three years later, in 2013, the combined cost fell below $2.00 per Mcfe.

With the current DD&A rate at $0.95, and cash operating expense at $0.15, we have reduced the combined expense of operating our properties and recovering our capital by 65% over the past seven years, and are nearing the $1.00 per Mcfe mark. As Jeff and Ray have both said, these costs and productivity improvements speak to the unique quality of our assets and execution capability of our team.

Cash flow for the second quarter was $93 million and cash flow per fully diluted share was $0.56. Second-quarter EBITDAX was $129 million -- both slightly below the first quarter of this year. Year-to-date cash flow was $192 million and year-to-date EBITDAX was $264 million.

Turning to the balance sheet, for the third consecutive quarter, Range ended the quarter with less debt than it started. The last time our debt was below the current level was May of 2012, a period when our daily production was 50% less than the second quarter of 2016.

Our bank credit facility, which has a $3 billion borrowing base and a $2 billion commitment amount, had only $3 million drawn at the end of the second quarter. Our existing committed liquidity is anticipated to be sufficient to fund potential cash requirements in the memorial transaction, and once approved by shareholders, no bank group waivers or other consents are required to affect the merger.

We closely -- we continue to closely monitor our recycle ratio, as we believe it is a key forward-looking indicator of our ability to grow our reserves and production within unhedged future cash flow. Based on our year-end 2015 reserve report, F&D cost, projected 2016 unit cost structure, and unhedged Nymex pricing for 2017, our recycle ratio is approximately 2 times.

Though the recycle ratio I just mentioned is based on unhedged Nymex prices, we remain well-hedged in 2016, with over 80% of our remaining 2016 natural gas production hedged at a floor price of $3.22 per Mcfe, and just over 330 MMBTu per day of our estimated 2017 gas production, is hedged at $2.94 per Mcfe. We've also added hedges to our oil and NGL position, which are detailed in the earnings release and Company website.

In summary, from a revenue and profitability perspective, second-quarter proved to be a lackluster story for us and the rest of the E&P industry, with low natural gas, oil and NGL prices coming off a mild winter and high energy inventories. Fortunately, industry production is declining and summer demand is upon us.

Nymex 2017 natural gas futures prices are much higher than 2016 historical prices, and our significant cost reductions and continued capital productivity improvements provide an added tailwind as we move into the last half of 2016. With the new Mariner East marketing arrangements up and running, and new takeaway capacity coming on later in the fourth quarter, we will be entering 2017 well-positioned for a future of disciplined capital-efficient growth with the opportunity to accelerate as warranted.

Jeff, back to you.

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

(Operator Instructions) Doug Leggate, Bank of America Merrill Lynch.

Jeff, it's interesting you described the quarter -- as Roger describes the quarter as lackluster, but the outlook is obviously still fairly -- could be whatever you want it to be in terms of growth rates. And I know I ask this question a lot, but what's the expanded asset base? Can you just help guide us a little bit as to how you think about where the balance sheet ranks relative to the -- sort of two major new areas, I guess, you are going to have in the expanded portfolio?

And what -- do we think about Range getting back to this legacy 20-plus-percent growth rate that you used to talk about? Just if you could frame how management is thinking about the longer-term picture?

Yes. Let me start shorter-term and then move out longer-term. But I think -- we've got, I think, two really high-quality assets, and I would argue the two best gas assets in the US, with room to improve both marketing advantages, location, the whole thing -- where the infrastructure is, differentials on Memorial, all those types of things, really positive. And the ability -- not only are they good, we think we can make them better.

So we're in good shape this year. But I think when you look forward, I think a couple of things will happen. One, I think you will see continued improvement as we go forward -- and we've got a great track record of doing that -- it's really early. And Doug, as you know, we don't set our 2017 capital budget until December.

But when we look at current forecasts and current strip pricing, where things are today, with our current estimates, we think the combined Company would have an organic growth rate of about 10% while spending at or near cash flow. As we project forward, we believe -- for some of the reasons that I said, and I won't go into detail unless somebody wants me to -- but if you look in our IR slides, there's a series of slides looking at gas production in the US, both supply and demand.

And we think when you look at supply and demand, there's a good story brewing for gas -- gas production declining; we're in the highest quality pieces, but oil and gas -- associated gas with oil declining at a time when gas demand is growing. And personally -- and I think our team believes -- gas is a cleaner, better fuel.

So, as you look forward, and as gas demand grows -- and I think your company's deck shows it -- gas prices, as you go out, look better. So as our cash flow increases, we have the ability to reinvest, and reinvest quickly, and to ramp up with increased cash flow as gas prices improve.

So right now, looking at where strip currently is -- realizing strip is a bad predictor for our future prices -- but even at where strip is, I think next year somewhere around [$3.10] -- that's organic growth of about 10% allocated, and both sides can grow. Both sides -- I think the Memorial and Range both have strong economics right now. We see they're probably about equal.

We expect to invest cash flow in both, and both can get organic growth of about 10% at strip prices for next year as prices improve, and we have the ability, cash flow increases. And we can -- we have plenty of places to drill, to be able to ramp, to get back to higher growth rates when prices warrant. So it's kind of a long-winded answer, but hopefully, I answered your question.

Yes, it's -- spending within cash flow, I think, is the piece I was really trying to get at. So, we should basically consider the balance sheet, the deleveraging event, obviously which occurs at the end of this year -- are you then comfortable that the balance sheet is where you want it to be? I just kind of -- want to see how that ranks relative to your growth aspirations?

Yes -- Doug, this is Roger. I'll take that one. And first of all, I just want to mention that my comment was that from a revenue and profitability perspective, it was a lackluster quarter.

I think from an operations and cost control standpoint, it was a terrific quarter. I just want to make that clarification.

That's what I was getting at. Right.

Okay. As for the balance sheet, we were real happy with where we sit right now. As I mentioned, debt is lower at the end of the quarter than the beginning -- three consecutive quarters running; aggregate debt, lowest it's been in four years, even though production continues to grow healthily.

I think you're looking at a balance sheet where, with the Memorial transaction, the leverage ratio -- that's EBITDAX -- will be well below 4, and I think that's where it needs to be. And with positive recycle ratios of two times for both companies on an unhedged basis, what that's telling me is that we will be able to grow within cash flow powerfully, and have the optionality to either bring the leverage down, if that's what's called for, or expand growth, if that's what's the better option.

Thanks, Roger. I'll let someone else jump on. Thank you.

Thanks, Doug.

Pearce Hammond, Simmons Piper Jaffray.

Good morning, guys, and thanks for taking my questions. My first question is, it looks like you are completing eight more wells this year. Just curious what's driving that? And I assume that's not going to have an impact on your 2016 production, but is going to certainly help your 2017 trajectory.

Yes, it's a good question, Pearce. And a lot of it is the operational efficiency and the reductions in capital that we're seeing. The -- what I talked about for the water -- $18 million savings; $9 million worth of savings in facilities.

It's what we do every year, is we take those improvements, and whether it's drilling more feet of lateral for less cost, or whether it's fracking more stages in a day, or combined with the fact that the wells continue to do better than we project, and flatter declines and shifting more to dry -- you know, all of that stuff helps us optimize our capital allocation, if you want to look at it that way.

And what we generally end up doing is we either drill more wells, complete more wells, kind of on the end of the schedule, which means we may turn those wells in line -- those eight more wells in line, but they will probably be really close to the end of the year, which really impacts our growth in 2017, and helps set that up much better. So that's typically what happens every year.

Well, thanks for that, Ray. And then my follow-up -- this is maybe a hard question to answer, but if we look at the [Ford] gas strip, 2018 Nymex is trading about $0.10 to $0.20, you know, $0.15 below 2017. I'd love to get you guys' thoughts on that. Do you think that's the market basically saying, hey, in 2017, the industry is going to overdo it like it has done in the past, and it's going to really hurt 2018? Or what might the market be missing when you look out there? And does that affect any of your hedging plans?

I think the key thing to look at -- and there's been multiple studies and people have done it -- is when you look at the marked-forward strip, and then you look at what actually occurs at that point in time -- whether it's six months out -- two, three, five years -- and the strip is an extremely poor predictor of the future.

So I think again, if you look forward -- and we have stuff in our IR presentation -- there's a lot of natural gas demand coming. I think power generation -- ultimately, long-term, I think gas is going to be -- continue to take market share. It's a cleaner better fuel regardless of which administration gets in or what the laws are; it's just -- it's a better fuel.

Gas exports to Mexico have surprised to the upside; I think that will continue to happen. LNG exports -- we think at least 8 [P's] per-day go, and that's already started up. A lot of petrochemical demand coming on in 2017/2018. And I think once the infrastructure gets built and gas starts moving around, it's a cleaner, better fuel.

Now Roger just went through a little symposium with a high-powered professor from the University. He puts it differently -- he says the world's moving to lighter -- will move to lighter molecules. You know, basically there's gas C1H4, there's more hydrogen atoms per carbon atom than there is for coal or oil or other fuels; it's a cleaner, better fuel. So, I think the strip is just a poor predictor of the future.

Thank you very much, Jeff.

Sure. Thank you.

Subash Chandra, Guggenheim Partners.

Slide 11 -- 2018 FT capacity -- do you have a guide as to what that might look like?

I'm not sure exactly what the question is. I'm on slide 11, but --?

Yes. So 2017 is an average of [1.375]. Do you have an 2018 (multiple speakers) -- look?

It will be the same. Yes, this is -- Subash, this is Chad. On slide 11, you see average for 2017 is 1.375 [B's] a day; 2018 will be the same, because that number includes Rover at the end of the year. It's average. (multiple speakers) So it'd be higher, yes.

Yes. It actually goes up some, because Rover comes on right at the end of the year. So this is a yearly average. Our yearly average would be higher and going up. I think the other team, our marketing guys have done a good job of is, we have kind of right-sized firm transportation, plus we were first movers. So we have right-sized transportation at a lower cost than our peers.

And you know, I think we still think ultimately, long-term, capacity tends to get overbuilt in the basin, so we didn't over-buy. So I think we're in good shape for our projection. It's a good match of transportation to our growth profile in what we have.

And it's a very diverse set of takeaway capacity, so -- that we're not dependent upon any one particular project, be it on time or not. I mean, we believe that all the projects we've got, looking at us going forward, are definitely on time, but we're not totally dependent upon any one of them. So I think our team has done an excellent job of spreading that out in that diverse portfolio.

On slide 11, another key part is that bottom line. As transportation -- as gas continues to move out of the basin again, at the end of 2016, over 70%, and at the end of 2017, over 80%, it's probably closer to 85% when Rover kicks on. You can see our -- the estimated Marcellus differential and Nymex improves. So we expect improving natural gas prices, better differentials, better netbacks going forward.

As we continue to move gas out of the basin, a lot of that incremental capacity goes to the Gulf Coast where the demand is going to be. And I think it's important to note as well on our NGLs, we only had a partial year. Really, Mariner East started up day one (multiple speakers) -- yes, partial quarter, partial year.

So as you look into 2017, the pricing should get better for NGLs as well. We'll have a full year of Mariner East. We have a new condensate agreement I think Ray mentioned, so we'll have a full year of that.

The other thing is, again, we expect natural gas prices to get better going forward, but there's a good story brewing for NGLs as well. A lot of ethane demand coming on. We -- Range being the first company to export ethane by ship with -- in partnership with Sonoco and INEOS, but Enterprise is starting to export a lot of ethane later this year, coupled with all the petrochemical demand that comes on in 2017 and 2018.

So the US's biggest propane exporter will be a large ethane exporter and increasing demand. So there's a good story brewing, not just for natural gas, but for NGLs, and for -- specifically for Range, because of the specific agreements we have. Then back to the macro -- as more ethane comes out of the gas stream, it helps a little bit on the supply side as you take the ethane out of the gas stream.

All right. And if I could just ask you about Northeast Marcellus -- volumes were down understandably; there were no completions. I suspect that goes back into growth mode. And I guess what I'm getting at is, as you look at the optionality of your portfolio, should we read the increase in takeaway as a desired growth rate over time? Or do you think of deemphasizing Northeast Marcellus over time to where you really want more optionality instead of growth, if you have to rank one versus the other?

Well, I think if we ranked anything, it would be returns. So we're not focused on growth as much as we are focused on returns. Growth just kind of falls out of that. Having a portfolio is good and having multiple choices is good, but it's a combination of where do we think we're going to get best returns with time? And we'll allocate capital that way.

And when we close on Memorial, it will give us another good choice because there's high returns there. So we'll have the ability in the Marcellus Northeast/Southwest; we'll have the ability of wet/dry/super-rich; we'll have the ability of Lower Cotton Valley. And I think having more high-quality choices ultimately will result in stronger returns with time.

Okay. Thank you.

Thank you.

Jeoffrey Lambujon, Tudor, Pickering, Holt.

The three pads you highlighted with the EUR projections look to be around 20% to 30%-plus better versus your average currently in those areas. I think you mentioned two of them being near existing pads, and having permits to drill 42 more wells on existing pads. Is that the opportunity set for this type of high graded drilling in the near-term? Or to what extent can you high-grade further in 2017 and 2018 to your best acreage, where you'll find that kind of outperformance?

Well, that's a great question, Jeoffrey. And we're really doing that all the time. We're continuing to improve completion designs and targeting and reservoir modeling. And I think you've seen that quarter-after-quarter-after-quarter, where we've continued to develop better and better well performance on a normalized basis or however you want to look at it.

We have lots of opportunities in all those areas that I mentioned. And remember, we have a huge position across Southwest PA. And we talk about super-rich, wet, and dry. And each one of those, by their selves, are larger than most of our peers' total position. And when you break those positions down internally, each one of those positions has lots of different unique designs and unique reservoir models, and unique targets and all that.

And so we're always trying to manage -- trying to allocate our capital to the very highest return wells, but you also have to factor in the fact that -- of, is there room in the gathering system to put more wells in that area? All of those things have to fit in markets for how we're handling our firm transportation and all those things work into this big master plan over the five, 10-year outlook that we have.

So, I think you'll see, like we've done every year, I think our type curves will continue to improve. I think our averages improve. And what I was trying to get across in this -- in my prepared remarks is that we have areas that are continuing to get better and better, and are significantly above the average.

And I think as we drill longer laterals, and continue to improve our completion designs -- I mean, we're 12 years into this, and we're still finding better wells. And we're going back into some of those areas and doing that. And we have opportunities to drill brand new pads that, in a lot of cases, may have better economics than going back to an existing pad.

It just depends on all of those things. So, it's a good point. And yes, I think we are going to continue to drive things up -- well performance-wise, capital efficiency-wise, cost structure is going to get better. You are going to continue to see those step changes year after year after year.

Great. Thanks for the detail.

Neal Dingmann, SunTrust.

Say, Ray, you and Jeff and the guys seem to be highlighting, a little bit more this time than in the past, the returning to some of the existing pads, like you mentioned on slide 42. Just wondering -- how do you think about this just simply and as far as improved potential well returns, and then versus the need to hold acres to drill? Because it certainly seems you have tremendous opportunity to come back and save costs that obviously improve returns here. So I'm just wondering -- how do you balance this with the need to hold acreage?

Well, at the end of this year, we've talked about, for the last several years, how we had a pretty significant land budget. And I can't quote the numbers off the top of my head, but we've significantly reduced our land dollars over the last couple of years for sure.

At the end of this year, we finally reached that point where we are largely HBP'd. There's always going to be a little bit of acreage out there, but it's largely done. We virtually have no acreage at risk at the end of this program this year.

So, going forward, that is much less of a factor than it's ever been. And so we will do what we've always done, is first look at returns and quality, and get room in the gathering system and all of those different things we need to look at. What -- the point I'm trying to get across in talking about the existing pads is, we have an additional opportunity and, I believe, a significant advantage over our peers in the area, in that we have all of that existing infrastructure that we can go back to.

We, in fact, even have permits in-hand where we could almost instantly put rigs on those locations and, in a couple of months, have wells online. I think that's a very unique advantage. We're not saying that's exactly where we're going to go next year. I think you're just going to see a mix of that plus new wells.

We've also got some miles in brand-new areas that are making 4, 4.5 Bcf per 1,000 foot at $5 million in some cases. That's pretty impressive economics. And those wells will greatly compete with going back onto existing pads. You can save up to $800,000 or $900,000 on a well on an existing pad -- it still may not compete with some of these really prolific areas that we're able to develop today.

So, it's always a mix of allocating that capital amongst that, but the good news is, going forward, we don't have that anchor of needing to HBP acreage around our neck any further going -- now going forward.

Wow, that's great to hear. And then just a quick follow-up. Just on that slide 47, you guys talk about that third Utica well appearing to be not only one of your best, but obviously one of the best plays. Even with that said, I guess you guys mentioned in your prepared remarks that these returns, you don't think, are still competing quite yet with some of these great Marcellus returns.

So is it just simply a return question to decide when you start? Or, if you start drilling more Utica wells, given you are holding that with Marcellus? I don't -- just I guess my question is, are you looking at just simply returns or is there more to that?

It's basically that -- returns. I mean we can -- we think we can do an 8,500 foot lateral in the Utica today for about $14 million. But -- again, that's 2.5 times more cost for essentially the same reserves as our dry Marcellus, some of the really prolific stuff we're developing in the very same area.

So, we have a huge inventory of Marcellus left to do. We have hundreds and hundreds, if not thousands, of wells to drill. And so I think that it really is going to be a matter of return. So we're going to continue to look at it. We may or may not drill a well next year; we haven't made those plans yet.

But I think we'll continue to develop the reservoir models, and I think there will be a point in time where it will definitely be a complementary development. And you'll see us kicking that in, whether it's a new contract to sell gas somewhere or whatever, you know. But I think that for the current time, there's just -- it's just simply it can't compete with the Marcellus today, for us. I think if you don't have Marcellus like we have, and that's all you've got, then that's what you do.

That makes sense. Great details. Thanks, Ray.

Ron Mills, Johnson Rice.

Just a quick follow-up on an earlier question about the improved productivity per lateral foot in each of those areas you highlighted. How does that compare with your comment, Jeff, about able to grow about 10% out of -- while being internally funded? In other words, is that growth within your cash flows based on what your average 2016 program is? Or -- and do those results point to even -- a better 2017 to 2019 growth profile because of that recoverability?

Yes. It's a good point. What I said in there is, I said based on our current forecast and utilizing current strip pricing, we get growth of about 10% spending at or near cash flow. As we continue to see improvements with time -- and you are talking about going out there to 2018/2019 and beyond, I expect -- I agree with Ray. I think we're not at the end of our efficiency.

So I think as we continue to extend laterals and optimize, and hone in on better areas and infrastructure, build out all those things, I think we can get better with time. All of that would allow for increased cash flow for the same dollars spent, which would allow us to either accelerate production and growth rate or balance sheet or whatever we choose to do with that. But as -- again, we also expect gas markets and NGL markets to improve with time. So that would say we've got strong returns that we think will get significantly better into the future.

Great. And then [Underwood departure] is expected to close in -- towards the end of this quarter. But the slides you added on the overpressured Lower Cotton Valley, really highlighting that position, seems more expensive than just the Terryville field is just also in terms of foreshadowing. Any comments on what the increased Lower Cotton Valley commentary can mean?

Yes, that's a good question, Ron. We think Terryville is a great field and there's a lot of additional drilling to do there, stacked pay potential, and just like we've been able to improve the Marcellus with time and believe we still can, we think that there's things we can do to improve the different intervals in Terryville. So both high-quality fields but your point is a good one, that it's not just that, it's Terryville but there's 220,000 net acres that comes with Memorial. So that's a big footprint and a big position and importantly, it's anchored by a couple of really high-quality fields, Terryville in the north and Vernon Field towards the south of that position. Vernon Field actually production-wise is better than Terryville and at the vertical well is worth significantly better -- in fact, so good that it was developed on a vertical basis.

But the point being, when you look at Terryville/Vernon and in addition across that 220,000 acres, there's a number of vertical tests and they show multiple things. One, with all the well control, vertical well control, it shows high-quality sands that exist in Terryville and in Vernon are present really across that 220,000 acres. So the sands are present and they are good quality. Another thing when you look, there's multiple gas tests out there in those vertical wells so not only is the sand present with good quality, it's also gas-saturated.

Then I think another key concept that's true really in the industry is that a horizontal well is a multiplier of a vertical. For instance, in the Marcellus Field, vertical wells if they average in an area half Bcf per well and then in the horizontal you pump a total of 30 stages, in essence then half [base] times 30 stages, you end up with a 15 Bcf well. And we see in the Terryville area, not just from Terryville but from other fields in the area, that it's the same thing, where you have fit the horizontal as a multiplier of a vertical and if you've got good vertical production it should lead to good horizontal wells. Bottom line, we think there's significant potential not only in Terryville but we think there is significant upside to the 220,000 acres that comes with it.

Due to technical difficulties on the part of their service provider, the call was ended at this time. If you have additional questions, please follow up with the Range Resources IR team. Thank you.