Laith Sando - Vice President - 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 Chad L. Stephens - Senior Vice President-Corporate Development

Doug Leggate - Bank of America Merrill Lynch Pearce Hammond - Piper Jaffray & Co. (Broker) Subash Chandra - Guggenheim Securities LLC Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Ronald E. Mills - Johnson Rice & Co. LLC

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 a 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 speakers' remarks there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir. Laith Sando - Vice President - Investor Relations: Thank you, operator. Good morning everyone, and thank you for joining Range's second quarter earnings call. The speakers on the 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've posted on our website. We'll 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'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. In addition, we've posted supplemental tables on our website to assist in the calculation of these non-GAAP measures and to provide more detail on both natural gas and NGL pricing. With that, let me turn the call over to Jeff. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: 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 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, resulted 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 DD&A was $0.95 in the second quarter, down 22% year-over-year. We continued 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 Marcus Hook 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 on-line or on schedule, including Spectra's Gulf Coast expansion in the fourth quarter of 2016, Columbia's Rayne/Leach Xpress in third quarter of 2017, and Rover Phase 2 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 U.S. 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 on-line, would result in additional of $4 billion of capital per year. It's also important to note that the drilled 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 U.S. 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 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's 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 and 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 transferrable 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 a 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 U.S., 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. Ray N. Walker - Chief Operating Officer & Executive Vice President: Thanks, Jeff. We continue 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 cost 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 of 1.41 Bcf equivalent 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've 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're 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 cost. 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 frac 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 cost; 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 cost 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 cost. 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 frac 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 costs 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'll begin to appreciate the improving capital efficiency 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 cost 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 in 30 stages in the 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 rate to 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 rate to 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 on-line 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 of these well costs that are referred 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 on 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 on-line 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 could 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 and volumes at much less cost than others that don't have a deep acreage and existing pad inventory. Consider in Pennsylvania the 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 on-line 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 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 take-away 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/Rayne 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/Rayne 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 1. 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 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 to 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'll 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. Roger S. Manny - Chief Financial Officer & Executive Vice President: 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 costs, which is largely responsible for the record low $0.15 per Mcfe cash direct operating expense. We also saw meaningful reductions in contract pumping, well-head 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 costs 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 costs fell below $3 per Mcfe, and three years later in 2013, the combined costs fell below $2 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 per Mcfe mark. As Jeff and Ray have both said, these cost 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 for the Memorial transaction, and once approved by shareholders, no bank group waivers or other consents are required to effect the merger. 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 two 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 – it's 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 take-away 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. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Operator, let's open it up for Q&A.

Thank you, Mr. Ventura. The question-and-answer session will now begin. And our first question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead. Doug Leggate - Bank of America Merrill Lynch: Thank you. Good morning, everyone. Good morning, Jeff. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Good morning. Doug Leggate - Bank of America Merrill Lynch: Jeff, it's interesting you described the quarter – or Roger described 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 two major new areas that you're going to have in the expanded portfolio? And do we think about Range getting back to the sort of legacy 20%-plus growth rate that you used to talk about? Just if you could frame how management's thinking about a longer-term picture. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Yeah. 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 they're the two best gas assets in the U.S., 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, but 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'll 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've 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 U.S., 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, 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 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, so 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, we can – our – we have plenty of places to drill to be able to ramp to get back to higher growth rates when prices warrant. So it was kind of a long-winded answer, but hopefully I answered your question. Doug Leggate - Bank of America Merrill Lynch: Yeah, 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 of that 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. Roger S. Manny - Chief Financial Officer & Executive Vice President: Yeah, 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. Doug Leggate - Bank of America Merrill Lynch: Right. Roger S. Manny - Chief Financial Officer & Executive Vice President: But as for the balance sheet... Doug Leggate - Bank of America Merrill Lynch: That's kind of what I was getting at. Right. Roger S. Manny - Chief Financial Officer & Executive Vice President: Okay. As for the balance sheet, I mean, we're 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 four, 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'll 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. Doug Leggate - Bank of America Merrill Lynch: Thanks, fellas. I'll let someone else jump on. Thank you. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thanks, Doug.

Our next question comes from Pearce Hammond with Simmons Piper Jaffray. Please go ahead. Pearce Hammond - Piper Jaffray & Co. (Broker): Hi. Good morning, guys, and thanks for taking my questions. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Good morning. Roger S. Manny - Chief Financial Officer & Executive Vice President: Good morning. Pearce Hammond - Piper Jaffray & Co. (Broker): My first question is, it looks like you're 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. Ray N. Walker - Chief Operating Officer & Executive Vice President: Yeah. It's a good question, Pearce. And a lot of it is the operational efficiency and the reductions in capital that we're seeing. 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. 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 on the end of the schedule, which means we may turn those wells, those eight more wells in line, but they'll 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. Pearce Hammond - Piper Jaffray & Co. (Broker): Well thanks for that, Ray. And then my follow-up, this is maybe a harder question to answer, but if we look at the forward gas strip, 2018 NYMEX is trading about $0.10 to $0.20, $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 is really going to hurt 2018? What might the market be missing when you look out there? And does that affect any of your hedging plans? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: I think a key thing to look at, and there's been multiple studies and people have done it, is when you look at the 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 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 eight B's (39:09) 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. Roger just went to a little symposium with a high-powered professor from a university. He puts in differently. He says the world's moving to – will move to lighter molecules. 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. Pearce Hammond - Piper Jaffray & Co. (Broker): Thank you very much, Jeff. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Sure. Thank you.

Our next question comes from Subash Chandra with Guggenheim Partners. Please go ahead. Subash Chandra - Guggenheim Securities LLC: Yeah, hi. Slide 11, 2018 FT capacity, do you have a guide as to what that might look like? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: I'm not sure exactly what the question is. Well, I'm on slide 11, but... Subash Chandra - Guggenheim Securities LLC: Yeah. So 2017 is an average of 1.375. Do you have an 2018? Early look? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: No, we... Chad L. Stephens - Senior Vice President-Corporate Development: It'll be the same. This is – Subash, this is Chad. On slide 11, you see average for 2017 is 1.375 Bs a day. 2018 will be the same, because that number includes Rover at the end of the year. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: The... Chad L. Stephens - Senior Vice President-Corporate Development: It's average. So it would be higher, yes. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Yeah. It actually goes up some, because Rover comes on line right at the end of the year. So this is a yearly average. So our yearly average would be higher and going up. I think the other thing our marketing guys have done a good job of is, we have kind of right-sized firm transportation, plus we were a first mover, so we have right-sized transportation at a lower cost than our peers. And 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 and what we have. Ray N. Walker - Chief Operating Officer & Executive Vice President: Yeah. And it's a very diverse set of take-away 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. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: On slide 11, another key part of 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 to NYMEX improves. So we expect improving natural gas prices, better differentials, better net-backs 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's 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 May 1.

First quarter. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Yeah. 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, Range being the first company to export ethane by ship with – in partnership with Sunoco 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 U.S. is the biggest propane exporter, will be a large ethane exporter. And increasing demand. So there's 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. Subash Chandra - Guggenheim Securities LLC: All right. If I could just ask you about Northeast Marcellus, the 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 take-away as a desired growth rate over time? Or do you think of de-emphasizing Northeast Marcellus over time to where you really want more optionality instead of growth, if you have to rank one versus the other? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Well I think if we rank anything it'd be returns. So we're not focused on growth as much as we're 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 what drives 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. Subash Chandra - Guggenheim Securities LLC: Okay. Thank you. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you.

Our next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt. Please go ahead. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thanks. Good morning. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Good morning. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Sorry. The three pads you highlighted with the EUR projections look to be around 20% to 30%-plus better versus your average curves 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 grade 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? Ray N. Walker - Chief Operating Officer & Executive Vice President: 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 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 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 of those things work into this big master plan over the 5-year, 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 improved. 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're going to continue to see those step changes year after year after year. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Great. Thanks for the detail. Ray N. Walker - Chief Operating Officer & Executive Vice President: Uh-huh.

Our next question comes from Neal Dingmann with SunTrust. Please go ahead. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.: Good morning, guys. Say... Ray N. Walker - Chief Operating Officer & Executive Vice President: Good morning. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.: ...Ray, you and Jeff and the guys seem to be highlighting a little bit more this time than in the past the return into some of the existing pads, like you mentioned on slide 42. I'm just wondering, how do you think about this just simply 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 and, obviously, improve returns here. So I'm just wondering, how do you balance this with the need to hold acreage? Ray N. Walker - Chief Operating Officer & Executive Vice President: 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're largely HBPed. 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 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 on-line. 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 wells in brand new areas that are making four, four and a half 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 an existing pad. 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, now going forward. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.: 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, 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 guess my question is, are you looking at just simply returns, or is there more to that? Ray N. Walker - Chief Operating Officer & Executive Vice President: It's basically that, returns. We think we could do an 8,500-foot lateral in the Utica today for about $14 million. But again, that's two and a half 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 returns. 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. You'll see us kicking that in, whether it's a new contract to sell gas somewhere or whatever. But I think that for the current time, 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 got, then that's what you do. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.: That makes sense. Great details. Thanks, Ray.

Our next question comes from Ron Mills with Johnson Rice. Please go ahead. Ronald E. Mills - Johnson Rice & Co. LLC: Good morning. Hey, just a quick follow-up on ... Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Good morning. Ronald E. Mills - Johnson Rice & Co. LLC: ... 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? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Yeah. It's a good point. What I said in there is, I said based on our current forecasts and utilizing current strip pricing, we'd get growth of about 10%, spending at or near cash flow. As we continue to see improvements with time – and you're 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 again, we also expect gas markets and NGL markets to improve with time, so that would say that we've got strong returns that we think will get significantly better into the future. Ronald E. Mills - Johnson Rice & Co. LLC: Great. And then with the purchase expected to close towards the end of this quarter, but the slides you added on the over-pressured 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? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Yeah, that's a good question, Ron. Yeah. We're – we think Terryville is a great field and there's a lot of additional drilling to do there, a 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's a good one that it's not just that, the Terryville, but there's 220,000 net acres that comes with Memorial, so that's a big footprint in a big position. And importantly, it's anchored by a couple of really high-quality fields, so Terryville in the North and Vernon field towards the south of that position. And Vernon field, actually, production-wise, is better than Terryville in that the vertical wells were significantly better – in fact, so good that it was developed on a vertical basis. But at 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 that well control, vertical well control, it shows that those 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're 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. And 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, the old vertical wells, if they averaged in an area 0.5 Bcf per well and then in the horizontals you pumped a total of 30 stages, in essence then, 0.5 Bs times 30 stages, you end up with a 15 Bcf well. And we see in the Terryville area, not just from Terryville, but from some other fields in the area that it's the same thing where you have, that the horizontal is multiplier of a vertical and if you've got good vertical production in the fort, it should lead to good horizontal wells. Bottom line, we think there's significant potential, not only in Terryville, but we think there's significant upside to the 220,000 acres that comes with it.

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