Range Resources Corporation (RRC) Q4 2015 Earnings Report, Transcript and Summary

Good morning. Welcome to the Range Resources Fourth Quarter and Full Year 2015 Earnings Conference Call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir. Rodney L. Waller - Senior Vice President & Head-Investor Relations: Thank you, operator and good morning and welcome. Range reported results for the fourth quarter and the full quarter for calendar year of 2015 with record production, a continuing decrease in unit costs, significant proved reserve additions, and possibly the lowest drill-bit finding cost for 2015 of $0.37 per Mcfe. The speakers on the call today are Jeff Ventura, our CEO; Roger Manny, Range's CFO; and Ray Walker, our Chief Operating Officer. Range did file our 10-K with the SEC yesterday. It should be available on our website under the Investors tab, or you can access it using the SEC's EDGAR system. In addition, we have posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins, unit costs per Mcfe and the reconciliation of reported earnings to adjusted non-GAAP earnings that are discussed on the call today. Now, let me turn it over to Jeff. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you, Rodney. Given the challenging price environment, our capital spending budget for 2016 is projected to be $495 million. This will in essence result in two horizontal drilling rigs plus one air rig in Southwest Pennsylvania. And to put that in perspective, we entered 2015 with 15 rigs. So for 2016, we have significantly reduced our activity and are primarily focused in Southwest Pennsylvania. This year, we're projecting lower well costs, better marketing contracts and lower unit costs. This strategy generates good returns and preserves our efficiencies by keeping a minimal level of activity. Concerning asset sales, we have a signed purchase and sale agreement for Bradford County assets for $112 million. Our assets there consist of approximately $20 million per day of net production and about 11,000 net acres which is all operated by Repsol. This is our only outside operated position in the Marcellus. In addition, we're currently marketing our Central Oklahoma assets. It's also important to note and point out that we have approximately $1.3 billion of liquidity with no bond maturities due until 2021. For 2016, we have approximately 80% of our natural gas hedged at a floor of $3.24 Mcf. Unit costs are projected to continue to decrease into 2016 with the proceeds from our Virginia asset sales used to reduce debt by 24%, our interest expense per Mcfe should be lower in 2016 than 2015. Our Virginia assets also had higher LOE per Mcfe as well as higher G&A and broker gas marketing expense. Given the sale of our Virginia assets last year, coupled with the closing of our Oklahoma City office, staff reductions in our field offices last year and a recent workforce reduction in our Pittsburgh area offices and Fort Worth office. Our head count today is 31% lower than it was this time last year. Bottom line, we're projecting that on an absolute basis, interest expense, LOE and G&A will decline year-over-year. As you'll see from the release, transportation and gathering per Mcfe will increase, but given the better contracts and better price realizations, we're expecting improvement netback pricing. The Mariner East pipeline is expected to result in better netbacks for both ethane and propane. Range is the only producer on Mariner East. We control a dominant portion of the capacity on the pipe and has considerable access for propane cavern storage. With our unique contracts, we expect to generate significant pricing differentiation for these products going forward, especially during the summer of 2016. Given a full year of Spectra's Uniontown to Gas City transportation and better basis for a gas which we have locked in a significant portion with hedging, we're expecting better natural gas netbacks to more than offset the increase. As an example, this project contributed to our $0.41 per Mcf price differential improvement in the fourth quarter as compared to the third quarter. Our IR team has given more color for 2016 in our release. The capital efficiencies our team is achieving are very significant. This is particularly impactful when efficiencies are combined with the quality of the rock that we have. We believe this is one of the key differentiating investment attributes of Range. We believe Range has the highest expected EUR recoveries on a per lateral foot in the Southwest portion of the Marcellus play combined with the lowest cost per lateral foot. What's important is that we're drilling laterals that are up to 1,000 feet longer with significantly lower cost ranging from 14% to 20% less total well cost per lateral foot including facilities. The EURs of these wells average 2.4 Bcf per 1,000 foot up to 3 Bcf per 1,000 foot. The absolute EURs are 16 Bcfe to 21 Bcf per well. Remember, we do have wells that are significantly higher than the average is. What's important is that the EURs per 1,000 foot of lateral are holding constant and we're achieving that performance in less time and with less cost resulting in improved capital efficiency. Lastly, I will summarize our reserve report for year-end 2015 that was released last night. Adjusting for asset sales last year, our reserves increased from year-end 2014. The drill-bit finding costs with provisions was $0.37 per Mcfe and our drill-bit replacement 436% or production including price and performance revision. Proved developed reserves increased from 52% to 55% and Marcellus reserves compose 97% of the total. Although the SEC proved reserve net present value decreased due to the significant commodity price decrease year-over-year. The year-end 2015 PV10 value of the proved reserves using future strip prices and current sales contracts is $6.8 billion which is very comparable to the year-end 2014 value of $6.9 billion. The continuing strong PV10 value is a result of continued capital efficiencies, reduced operating cost and improvement in netback pricing with the commencement of our most recent sales contracts and scheduled future contracts. For further comments on unit cost reductions as well as the balance sheet, I'll now turn the call over to Roger. Roger S. Manny - Chief Financial Officer & Executive Vice President: Thank you Jeff. The fourth quarter capped a year of solid operating progress. Range achieved consistent production growth with improved capital efficiency paired with significantly lower unit costs. Perhaps most importantly, for the second year in the row, we ended the year with lower debt than we started. Over the past two years, production has increased 48% while debt has been reduced by approximately $0.5 billion or 14%. Starting with the fourth quarter income statement, higher production and lower costs were no match for significantly lower year-over-year commodity prices. There were some bright spots, however. Cash margin during the fourth quarter was $1.52 an Mcfe, approximately 20% higher than the previous two quarters of this year. And both EBITDAX and cash flow were higher in the fourth quarter than the two preceding quarters of this year. Fourth quarter reported net loss was $322 million, driven by a $409 million pre-tax loss on sale of assets and an $88 million pre-tax impairment of legacy Midcontinent proved reserves. Fourth quarter earnings, calculated using analyst methodology which eliminates non-cash and non-recurring entries, was $42 million or $0.25 per fully diluted share. Cash flow for the fourth quarter was $204 million and EBITDAX was $241 million, both slightly more than 20% below last year's fourth quarter figures due to 30% all-in lower realized prices. Fourth quarter cash flow per fully diluted share was $1.22. Cash flow and EBITDAX for the full-year 2015 was $740 million and $897 million respectively. Cash flow per fully diluted share for the full-year 2015 was $4.45. There were a few unusual fourth quarter expense items that merit comment. And while most all expense categories came in at/or below guidance, transportation gathering and compression expense was $0.05 over guidance at $0.85 due to some new capacity coming on earlier than expected. Direct operating expense came in at $0.22, $0.06 under guidance, mainly due to a non-recurring $0.03 credit. Speaking of unusual and non-recurring items, just to give everyone a heads up, next week, we will be filing a registration statement to exchange our 4.875% senior notes issued last year under Rule 144A with lifetime registered notes. We're also registering some shares that are already issued and in the deferred compensation plan. This is an ordinary course of business administrative matter and it's being done immediately after the 10-K filing just to save accounting expense. There are no changes to the note terms. Our fourth quarter earnings release contains detailed expense item guidance for the first quarter of 2016 and one item that you'll note in the guidance is the increase in projected gathering transportation and compression expense associated with commencement of the Mariner East project. As further discussed in the earnings release and as evidenced in our fourth quarter margin improvement from the Uniontown to Gas City pipeline, these new projects are expected to improve our margins by generating significantly higher revenue over the incremental cost. Another item of note in the earnings release is our decision to conserve cash by reducing our cash common stock dividend by half from a quarterly $0.04 a share to $0.02 a share. A highlight of every year's fourth quarter release is the annual reset of our DD&A rate reflecting the results of the year-end audited proved reserve report. With heightened focus on capital efficiency, this year's results are especially significant. Our fourth quarter DD&A rate dropped to $0.97 per Mcfe, moving closer to our finding and development cost. With our total company recurring direct operating expense of approximately $0.26, the combined cost to recover our asset depreciation and produce our oil and gas was $1.23 an Mcfe. Our dry gas Marcellus assets have an even lower DD&A rate and direct operating expense. But even using this $1.23 per Mcfe figure for the whole company, as recently as 2009, our combined total company DD&A rate and direct operating expense was $3.17, almost three times today's figure. In the first quarter of last year, we closed our Oklahoma City office, which reduced our company-wide head count by approximately 8%. As Jeff mentioned, walking that event forward to today, asset sales and additional reductions in force have reduced our total head count by 31%. While this has been extraordinarily difficult for an already lean organization, it demonstrates our commitment to do what it takes to not just survive in the current downturn but effectively position the company for the future, whatever lies ahead. Because our realized price peaked in 2008, we are already over seven years into a period that many are just now calling lower-for-longer. We already know what that phrase means, and we know what that phrase means we have to do. Besides dramatically reducing head count and high-grading our assets, here's another illustration of the type of positioning for the future I'm referring to. In our reserves release, you'll see that we have a $0.40 per Mcfe proved undeveloped conversion cost, a modest 0.4 well proved undeveloped/proved developed producing booking ratio, meaning that for every PDP Marcellus well, we'd only have 0.4 PUD wells offset booked. And you'll note that our PUD reserves are limited, not by economic value but by the SEC five-year rule. Now, not mentioned in the release is that we have 124 fully constructed and operational Marcellus drilling pads holding five or fewer wells with, in most cases, room to drill up to 18 wells or more on each pad. Now, this means that for every PUD well we convert to a PDP well, there is another one ready to book on an existing pad with already built-out infrastructure. With 124 lightly drilled pads already constructed and tied in, we can economically grow reserves in production in this fashion for many years. Plus, we have another 59 pads with six to nine wells on them, and these pads have the same lower-for-longer economics. We've included in the supplemental tables posted to the website a slide which takes the economics behind this illustration full cycle. Starting with our actual fourth quarter 2015 $1.66 per Mcfe total cash cost, then adding the $0.40 F&D cost, then adding our fourth quarter $0.35 an Mcfe basis differential, it totals to a basis adjusted all-in cost of $2.41 an Mcfe, which generates excellent margins against our $3.24 2006 hedged floor price. But more importantly, this current all-in cost figure is more than covered by current strip prices in 2017 and beyond. If things get even more challenging, note that the $0.40 F&D cost number in the reserve report is an average across all the company's proved undeveloped locations. Actual F&D cost will vary by well type and location, and we have the option to select from 183 existing pad sites, allowing us to optimize the development activity to match market conditions. Now, Ray is going to unpack this illustration a bit more during his remarks in just a few moments. Now, positioning Range for 2017 with a recycle ratio over one times, unhedged at current strip prices, gives us confidence that we can continue to grow within cash flow even in this challenging environment. We believe that an underappreciated key metric to balance sheet preservation lies not in the rearward looking balance sheet ratio debt-to-EBITDAX, but in a forward-looking income statement ratio like the unhedged recycle ratio. If your unhedged recycle ratio isn't above one times, reducing debt or stockpiling cash only buys you time, it doesn't buy you success. This doesn't mean that we're ignoring the balance sheet, however. At year-end 2015, our bank credit facility balance outstanding was $95 million. That's down from $723 million at year-end 2014. We've got approximately $1.3 billion in current available liquidity. Our earliest bond maturities, as Jeff mentioned, is 2021. The weighted average interest rate on our bonds is 5.125% and our debt is 96% fixed. We have class-leading asset coverage with total debt per Mcfe of proved reserves of $0.23. And though we do not have a debt-to-EBITDAX ratio covenant, our debt-to-EBITDAX ratio at year-end 2015 was a very respectable and manageable 3.0 times. Lastly, our bonds continue to trade well against our peer group before and after recent rating agency actions. Range currently has approximately 80% of our estimated 2016 gas production hedged at a floor price of $3.24 an Mmbtu. The earnings release contains a summary of our hedge positions for all commodities of 2016 and 2017. Additional more detailed hedged volumes and prices can be found on our website. In summary, though our realized commodity price has declined every year since 2008, 2015 was the first year where Range was unable to increase cash flow and cash flow per share through higher production and lower costs. And while some may say this signals the bottom and better times are ahead, we've aggressively responded to the 2015 cash flow decrease by reducing and optimizing growth, carefully deploying capital to our best return wells, shedding additional non-core assets, further lowering our cost structure, improving our capital efficiency, having our dividend, protecting our liquidity, and continuing to operate safely in an environmentally sound manner. Much has been accomplished in 2015 and there is much left to do, but we're confident in the future of Range and we're going to manage our finances accordingly. Ray over to you. Ray N. Walker - Chief Operating Officer & Executive Vice President: Thanks, Roger. In 2015, we spent $814 million on drilling and completion which was 40% lower than the previous year and it resulted in 20% year-over-year growth even though the Mariner East project was delayed significantly from the original plan. This was a real testament to our team coupled with our high-quality and diverse asset base, meaning dry or liquids rich, and what we believe our best-in-class capital efficiencies. Focusing on Southwest Pennsylvania for a few highlights from 2015 as compared to 2014, we saw our drilling costs per foot of lateral decreased by 21% while drilling 24% longer laterals. Our completions team increased the number of frac stages per frac crew per day by 31%. We achieved a 15% reduction in water costs for our completions operations. And with operational efficiencies and service cost reductions, we recognized an average 33% decrease in total completion costs per well. And importantly, we expect these improvements to continue. For this year, our total capital budget is $495 million. This plan represents a 45% reduction in total capital from 2015 and a 69% reduction from 2014. Of that capital, 96% is directed towards drilling and completion with only $20 million in land. Essentially, all of our capital is directed towards the Marcellus with the majority of that being spent in Southwest PA. And you can find the details for all of that in our earnings release and in our updated presentation on the website. We're only spending about $18 million in Northeast PA this year which involves 14 wells coming online and a couple of wells drilled which will be completed later. Our fourth quarter production came in at 1.43 Bcf equivalent per day, slightly exceeding our guidance of 1.42 Bcf equivalent per day. And our annual growth was right at 20% as forecasted. Production for the entire 2016 year is expected to average 1.39 Bcf equivalent per day to 1.42 Bcf equivalent per day with 30% to 35% liquids. This works out to 8% to 10% production growth for the year on a pro forma basis adjusted for asset sales. Production for the first quarter of 2016 is expected to be approximately 1.35 Bcf equivalent per day with 30% to 32% liquids. This guidance accounts for the sale of the Virginia properties of $107 million a day on a pro forma basis. And on the pro forma basis would represent a 2% increase over the fourth quarter of 2015. Importantly, we expect to see a higher exit rate at the end of 2016 than we stated the year with after the asset sale. We'll also maintain an inventory of wells waiting on completion or tie-in that is consistent with our reduced activity levels and also consistent with past years. This should set us up well going into 2017. Jeff touched on the longer laterals, lower cost and resulting capital efficiencies in his remarks, and you can find the details and the economics behind those in our updated presentation. And Roger talked about the fact that we have an inventory of pads all across the core of the core with a demonstrated ability to drill wells with substantially less cost per well, so let me take a minute and walk through our three areas in the Marcellus and Southwest Pennsylvania and work all of this in together. First, we've updated our 500-foot spacing test and our infill test in our updated presentation on pages 40 and 41. Our tighter spacing projects now have almost six years of history and our infill project now has almost two years of data on the new infill wells. Both demonstrate success in our core acreage position in Southwest Pennsylvania, and we believe this is a distinct and unique advantage for Range. In the super-rich area, the 2016 wells are planned to average 6,700 feet which will be 24% longer than last year yet with the improved efficiencies and cost savings the completed well cost will be about the same which is $5.9 million. Now, I want to take a second here and remind everyone that all of the costs that we discussed here are total completed well costs and do include all the facilities. We're projecting the 2016 super-rich wells to cost $881 per foot of lateral which is a 20% improvement over 2015. We project the recoveries to be 2.4 Bcf equivalent per 1,000 foot of lateral. Said another way, we project spending $5.9 million to recover 16 Bcf equivalent, which equates to an F&D cost of $0.44 per Mcfe. Following, Roger's earlier point, if these wells were drilled on existing pads utilizing already existing infrastructure including the pad, roads, facilities, water and so forth, the total well cost would be significantly less and the F&D cost could then be as low as $0.38 per Mcfe. In the wet area, our 2016 wells are projected to have 7,000 foot laterals on average which is 17% longer than 2015. Given the increased efficiencies and lower costs, the wet area wells are expected to cost $5.8 million or $832 per foot of lateral which is a 16% improvement over 2015. These wells are projected to recover 3 Bcf equivalent per 1,000 foot. Again to summarize, we project spending $5.8 million to recover 21 Bcf equivalent which equals an F&D cost of $0.34 per Mcfe. Again if these wells were drilled on existing pad, the F&D costs could be as low as $0.29 per Mcfe. The Southwest dry area wells in 2016 are expected to average slightly longer at 7,000 feet versus 6,800 feet last year. Significantly, the cost is projected to decrease from $6 million to $5.2 million. That's $743 per foot of lateral which is a 14% improvement over 2015. Again, our projected recovery of 17.6 Bcf for $5.2 million in the dry area equals an F&D cost of just $0.36 per Mcfe. If drilled on existing pads, the F&D cost could be as low as $0.27 per Mcfe. In summary, by drilling on existing pads, our F&D cost in Southwest Pennsylvania could be in the range of $0.26 to $0.34 per Mcfe, which we believe would be the lowest in the play. As capital efficiency continues to improve throughout this year and beyond, we believe these F&D costs could go even lower, maybe as much as 10% lower, resulting in higher margins and even better recycle ratio for the company. Our inventory of existing pads on core acreage coupled with our continued improvement in capital efficiency and our low-cost structure give us a significant advantage in this low-price environment. It positions us well for 2017, and we don't believe this is the case for everyone. Capital efficiency is our focus and we're recognizing it in many ways. For example, in looking at our current plan for 2016, we're putting on line almost the same number of frac stages or if you say it another way, approximately the same amount of lateral feet for 43% less capital than we did last year while maintaining some of the highest EURs per 1,000 foot recoveries in the basin. We can do this because of the high-quality resource and plays that Range has captured over the past 11 years of development in its core position. We believe these achievements are not likely outside the core, and we believe they are unique to Range. Along with improving efficiencies from 15% longer laterals, we're continuing to achieve decreases in service costs this year as compared to last year. Our operating efficiency is among the best in the basin, and we have no long-term commitments for services. As an example, on the completions front, we're averaging over seven frac stages per day, per crew resulting in some very attractive service pricing for Range while still generating acceptable margins for the service companies. We believe this provides another unique advantage for Range. On the marketing side, Range has added some capacity over the last four months that we're really excited about and that we've been discussing for quite some time. Of course, with this capacity comes cost. The biggest driver of the increase in transport expense for 2016 is related to Mariner East coming online in the first quarter as well as additional ATEX capacity for ethane. Mariner East is expected to bring us better netbacks on our 20,000 barrels per day of ethane and 20,000 barrels per day of propane. The project started the commissioning process for ethane in late 2015, commissioned the refrigeration system in January then Range introduced ethane into the pipeline for the first time in February and we expect to be loading the first ethane ship in a few days. We'll begin shipping ethane to INEOS and we'll also be able to utilize VLGCs which are the largest ships available to ship propane while providing lower cost transportation and better netbacks. As a result, NGL realizations are expected to improve from approximately 18% in 2015 to 24% in 2016. And NGL volumes increase substantially, approximately 30% over 2015. The resulting increased revenue far exceeds the additional NGL transport expense, thus improving cash flow. On the gas front, we had a full quarter of the pipeline project Uniontown to Gas City by Spectra Energy. We'll have a full year of this for 2016 and this capacity is part of the reason for the improvement in our natural gas differentials when looking at the fourth quarter versus the third quarter or when looking at 2016 versus 2015. This project allows us access to markets in the Midwest and achieves pricing that is better than NYMEX. Fourth quarter 2015 natural gas differentials were $0.41 better than the third quarter, and full-year 2016 is expected to be $0.10 better than full-year 2015 differentials. These premium transport additions set us up well to improve our relative pricing for 2016 and beyond for both NGLs and natural gas. Next, I would like to bring you up to speed on our Utica wells. We're currently completing our third well as we speak. It's a 5,800 foot lateral completed with 38 frac stages averaging 500,000 pounds of profit per stage which is 50/50 100-mesh and premium 40/70. The well will be flowed back, tested and put on production under a managed pressure program, and we will not be trying to achieve a headline rate. The well is currently forecast to come in around $17 million including the production facilities. We're currently cleaning up the well for the initial flow back and then we'll be building production facilities, planning to turn the well to sales prior to the end of the second quarter. We believe that our next well's total cost, again including all the production facilities, would be in the range of $12 million for a 6,500 foot lateral. And we estimate a well with an 8,000 foot lateral would come in at approximately $14 million. The EUR of our first well remains in the range of 15 Bcf gross, and the second well is still expected to better than that. We're encouraged by these early results, and we see potential for further enhancements both in cost and in performance. However, in looking at the cost per thousand foot of lateral even on the next wells, we're in the $1.8 million range as compared to $743,000 in our Southwest PA dry Marcellus acreage. In simpler terms, the Utica costs almost 2.5 times more than our dry Marcellus while achieving about the same production. While the Utica represents tremendous future resource potential even with anticipated efficiencies, the returns from our Marcellus wells far exceed the Utica. Given limited production history thus far, on a risk-adjusted basis, it's clear that our high-quality Marcellus wells are the superior investment. Over time, we expect that the Utica can be a complementary development opportunity. But for now, our plan for the rest of this year is to monitor these wells along with offset wells while continuing to build our reservoir models and then determine a path forward from there. In the meantime, we will remain focused on our high-graded Marcellus core acreage with the best economics possible, and we'll continue to work to lower cost and improve capital efficiency. Now, back to Jeff. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Operator, let's open it up for Q&A.

Thank you, Mr. Ventura. Our first question comes from the line of Jon Wolff with Jefferies. Please proceed with your question.

Hey, guys. Good morning. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Good morning. Ray N. Walker - Chief Operating Officer & Executive Vice President: Good morning.

A few here. You may have been asked this before, but you obviously got a great price for Nora, but can you talk about what that does to your natural decline rate? Alan W. Farquharson - Senior VP-Reservoir Engineering & Economics: Yeah, Jon. This is Alan Farquharson. Our decline rate still stays relatively consistent with what it's been historically. The reason why the Marcellus has been such a dominant producer in terms of total production, if you think about it, last year we made about 1.4 Bcfe a day and Nora was 100 million, just using some round numbers. So the decline rate first full year still is around 19% and then declines. Within five years, you're back under 10% again. So that's pretty consistent with what we've seen over the last year. I think that a lot of people haven't really recognized how shallow the decline is in the Marcellus overall.

A little more granular on that. I mean, it's such a low number, given – without the tight gas sands of the past and without Nora. Would that be a testament to the sort of average age of wells because certainly first year declines are not anywhere near 20%? Alan W. Farquharson - Senior VP-Reservoir Engineering & Economics: Yeah, I think it's a function a little bit of the average age of the wells, but I think it's also – the first year kind of declines fairly steeply in a lot of these shale plays. But then I think most people probably don't look at year two, three, four, and five and then you see how flat some of the declines are. If you look at a lot of the historical data that's out on the PA website, you can see that those wells get fairly flat, relatively flat relatively quickly. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: I think an important point to note is if you look at Range's reserves year-over-year for the last 5, 6, 7, 8, 10 years maybe, our reserve revisions have been positive almost every year and really that speaks to the quality of rock and the wells are continuing to outperform. Again, that's not something that I think happens everywhere, but the fact that we haven't had reserve cuts and in fact we've got positive revisions gives our management team great comfort as well as our banking group. So part of that is – and if the wells are outperforming by definition than the declines are shallower. Ray N. Walker - Chief Operating Officer & Executive Vice President: And also I'll just add one more thing in, Jon. This is Ray. That I think if you look at our type curves that we updated in the presentation, you'll see that last year's production in a couple of those areas seems to be pretty flat and I think people don't realize, most of our wells come online under constrained conditions. So that first year decline that most people think is there is somewhat muted compared to a lot of other places. So I think that contributes to it also.

Just thinking about capital efficiency and the decade-long process of in-fill acreage drill, purchases and building pads which if you could remind me how much they cost? I think last year – one time you're in kind of single well pads and then more recently I think it was four to five or five to six per pad, wells per pad. Can you update us on that and also the cost of a well pad? Ray N. Walker - Chief Operating Officer & Executive Vice President: Sure, Jon. The pad construction phase or building a pad and a road can average anywhere from $400,000 up to $1 million depending on the terrain and the locale and whether it's got wet land streams next to it and all those sort of things that we have to do from erosion and sedimentation protections in Pennsylvania. So on average, $600,000 or so to $700,000 maybe. We have always drilled probably no fewer than three or four wells per pad, and in most cases, we average around five, I would guess. This is the current average. We can do some more research on that and see. But I think it's about five. We have drill pads up to 9 and 10 and 12 wells, but on average, it's about five. We have very few pads that are less than three or four anywhere from history. I mean, we had a few very far step-out pads early on that were one or two or three wells, but that's literally been maybe five, six, seven years ago. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Well, let me just add on to Ray a little bit. But like Ray and Roger were talking about, it really sets us up at this point for strong capital efficiency going forward and the optionality to go back to those pads and drill on those pads where you've got a lot of the costs already. And the team has done a great job. So going forward, there is a really built in capital efficiency, and I think it's a strong statement to say even in this environment. We have a recycle ratio greater than 1 by being able to... Ray N. Walker - Chief Operating Officer & Executive Vice President: Yeah, unhedged.

Yeah. That was the context of the question. I just wanted to get some numbers around it. The other thing on limiting the number of wells per pad, if I recall in the past, talking to you, some of it had to do with the takeaway infrastructure that would be required if you went to seven or eight wells per pad. Obviously, you don't own your own midstream company and maybe that's some of the factor. But it feels like – is there right sizing that – in terms of the amount of takeaway capacity that colors your view of how many wells per pad at least on the initial phase, I know you plan to go back to well those pads later? Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: We'll kind of tag team the question. I think if you look at slide 18, that kind of tells the story. We have a huge acreage position and what we think is the core of the ploy. So early on, we're limiting the number of wells per pad to be able to drill more pads, to be able to hold that position. And by the end of this year, we're basically done with that. On slide 18, when you look at the – and at this point, it's really well delineated. We've got basically combined potential in those horizons of about 1.5 million net acres stacked, predominantly down in Southwest PA. So we spread – so, for limited capital, we spread those pads out to hold it, but now going forward, it really sets up a strong efficiency to go back and drill on those particular pads. Ray N. Walker - Chief Operating Officer & Executive Vice President: Right. And Jon, it's been literally a 10-year – 9 or 10 year process of building infrastructure with MarkWest when you talk about the wet system for instance. And a lot of that is – the backbone of that system is finally in place. And I think another concept is when we go back to one of these pads, I don't think we'd be going back and drilling all 18 wells. We would go back and drill two, three, four wells to kind of fill in that room that's now available because of the natural decline of the system and so forth, plus the fact that, like Jeff said, we've been talking about for a couple of years now that we had targeted about 2017 when the HBP kind of factor would be almost gone, and we're literally on the precipice of that. So we can literally, starting in next year's plan, really focus on the highest returns and where there is room in the systems whether it's the dry systems in East Washington or the Allegheny County or in the wet system. We have that much flexibility and that diverse set of assets, like Jeff was referring to.

Last one since my mailbox is being inundated with the question around transport and gathering costs going up, and I assume that has a lot to do with Mariner East 1. I guess, my question is – I guess number one is, I think that's the big reason, but maybe confirm that. And then second, is propane at least getting a better revenue value than natural gas, and is there sort of a positive uplift from processing propane, understanding that these costs are fixed than some costs? Ray N. Walker - Chief Operating Officer & Executive Vice President: Well, I'll start. I mean, yeah. I mean, you're right. The additional costs are mainly from Mariner East starting up. And so we have that cost that goes on that line and the transportation on it. But it results in netback pricing both propane and ethane, that's far better than anything we've got in the past, so it way more than offsets and then Spectra's Uniontown to Gas City is a good example. The transportation cost on that line also gets added, but then when you net-net it all out, we're selling gas for sometimes $1 better than what we're selling it in to, results in $0.40, $0.50, $0.60, sometimes up to $1 better netback price. But I'll turn it over to Chad to talk a little bit more about propane.

Yeah, Jon. This is Chad. We have worked on – since we moved the in-service date of Mariner East, we worked with the (43:09). I think we announced that we had a long-term agreement with (43:13). They have a global presence, and they are helping us and advising us on selling propane into the international markets. So since we announced the arrangement with them, we've locked in arb between mainly Europe and what Mont Belvieu prices were. So with that arb locked in for all of 2016 and part of 2017, we've captured that value that's much better than Mont Belvieu. So it's much better than Mont Belvieu and it's better than gas that we could get on a gas price equivalent basis. Of late, you've watched freight, the Baltic Index on freight costs come way down. This time last year they were about – equivalent of about $0.12 a gallon to $0.14 a gallon. You can currently get a freight rate Baltic Index quote of about $0.035 to $0.04 a gallon. So the freight rates have played into our hand as well. So we're at the end of the day going to be able to get – at Houston plant, we're going to be able to get a Mont Belvieu equivalent to maybe minus $1 or minus $2 which is much better than any of our peers. So we're excited about Mariner East coming fully in service where we can take advantage of loading VLGC ships, lots of volume which will lower our per unit cost of shipping.

That helps. Thanks, guys. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you. Ray N. Walker - Chief Operating Officer & Executive Vice President: Thank you.

Thank you. Our next question comes from the line of Ron Mills with Johnson Rice & Company. Please proceed with your question. Ronald E. Mills - Johnson Rice & Co. LLC: Hey. Good morning. Ray, from a timing standpoint and as you talked about capital efficiency, at what point do you think you'd go back and start to drill again on those pads and be able to leverage the prior expenditures on the pad construction? Ray N. Walker - Chief Operating Officer & Executive Vice President: Well, Ron, it's a good question. We, for the last couple of years, we always seem to have a small percentage of our wellbore going back in an area and doing that. I think this year, there's a pretty small percentage of the wells that are on existing pads. I think really going into next year, and of course, we're just announcing this year's plans, so we've got a lot of work to do to figure out exactly what we're going to do in 2017. But I do foresee us probably starting to make more of a move towards that in 2017. Of course, a lot of it depends on pricing and what all happens this year and I think with the big capital cuts that everybody is going through and the rig counts falling and lots of people choosing not even to drill per se that we're going to see the gas production roll over and we're clearly seeing gas demand increasing. So it's just a matter of time before things start changing and I think we're going to have to get much later in this year before we see how that works out and exactly what our numbers are going to look like for 2017. Ronald E. Mills - Johnson Rice & Co. LLC: And I think part of it to go on one of the things that Jon mentioned was, from a infrastructure standpoint part of it, you never want to build capacity for peak production. And so when you look at your estimates of those pads, is the timing also driven by the fact when you start to gain capacity on some of those pads or is there something else driving that investment decision? Ray N. Walker - Chief Operating Officer & Executive Vice President: No. You're absolutely right. I mean, one of the driving factors in that whole plan will be exactly where we can put these wells, where there's room in the compression for instance, and process and capacity and all the different things that go into that, the markets, it's all a very integrated multi-disciplinary process that we go through. And we'll literally be working all this year as we – and we constantly optimize what we're doing month by month even right now. So that's always a big impact. You're correct on that. Ronald E. Mills - Johnson Rice & Co. LLC: And then lastly on just the NGL realizations, particularly related to Mariner East, is that something that begins to start up here at the very end of the first quarter, is it better just to model it beginning in the second quarter? And then associated, I think in the past you had talked about cash flows from the ability to access international markets or even local markets in the case of propane can generate an incremental $50 million or so of cash flow over a 12 month period. Do those numbers remain unchanged?

Yeah. This is Chad. We actually started taking our propane in kind in the fourth quarter of 2015. Mariner East was not fully in service. It was not fully refrigerated. So we still were loading on what's called handy ships, handy ships are smaller volumes, they can take about 150,000 barrels. So the per unit transportation cost is a little bit higher which our netbacks were not as good as with Mariner East fully in service, refrigeration is in service and we can load the VLGC ships. But our main focus on marketing the propane once it's fully in service is either take advantage of the arbs between Europe, Asia and Mont Belvieu and/or the local markets. We can sell into the local markets in, for instance, the winter months when propane prices spike if we get a polar vortex. So we have that optionality to be able to find the best price for the propane whatever time of year it is, if that makes sense Ronald E. Mills - Johnson Rice & Co. LLC: With the pricing throughout not flat, but it should have a smoothing impact on the prices through the year for NGLs, correct?

Yes. Ronald E. Mills - Johnson Rice & Co. LLC: Okay, perfect. That's all for me. Thank you.

And we're... Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: Thank you.

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed with your question.

Hey, guys. Good morning. Roger, I know we share the same love of the recycle ratio and appreciate you putting that slide on the website. I wanted to ask you kind of on the three variables that you could control in that equation. One on the F&D side of things, you threw a $0.40 number out right now. But you really highlighted that you move to infrastructure, you move to dry gas area, that could potentially come down lower. Curious on activity levels, you've got 37% activity geared to the dry gas areas right now. Can you increase that more going forward given this best economics? And then the second part of it is just on the confluence of the differentials and the transport costs. You guys have shown out to 2017 more downward pressure on the gas differentials. Curious if you – on slide four, you throw your cost on the transport side out to 2016, curious what that could look like going out to 2017? Thanks. Roger S. Manny - Chief Financial Officer & Executive Vice President: Okay, Mike. Yeah, let me comment on the recycle ratio and then I'll turn it over to Chad on the differentials. And you're exactly right, I share your enthusiasm for this ratio. I mean, we went through a period where in the old days F&D costs really mattered. And then we went through this period where everybody had oil and gas coming out of their ears and margins were great and then nobody really cared about it. It was all about margins. And now, I think, it's coming back into vogue and as it should be because, in times like this, positive recycle ratio unhedged, as I mentioned, I think is the key to keeping things afloat. The $0.40 number that we have in the slide that we posted, again, that's company average F&D just to convert the PUDs. My illustration was there that since you've taken about 1.2 Ts of PUDs that are economic off your books because of the five-year rule, to the extent you go back in there and pop a PUD and convert it on existing pad, you just move another well onto it to take its place. But the $0.40 covers all the PUDs booked across the entire company. And as Ray mentioned, in some of the areas of Marcellus like the dry gas, that number is down in the low $0.20s. So while the strip price is going to move and fluctuate, to your point, we can work the throttle and work that F&D cost as well. So that's a key variable for us. As for the 37% dry gas. I mean, we've got some infrastructure coming on on the dry gas gathering side that'll allow us to ramp that up going forward. But, again, those are kind of game-time decisions as we look across the portfolio. And Ray's team looks at having the optionality on 183 existing pads, do I want to drill a super-rich, do I want to drill a wet, do I want to drill dry. We have other contacts besides MarkWest in Southwest PA, so a lot of moving parts, a lot of variables, and it's just a matter of optimizing. So I think the key is having discovered the play and having been there for 11 years, that first-mover advantage of having just a whole lot more optionality in how we move forward in a tough environment.

So part of your question was discussing also future basis differential, and when you look at currently and going into 2016, Dominion South and M2 are still pretty much under pressure. But with some of these new projects, takeaway projects coming on line, the indexes are improving if you look at the forward curves of indexes. (53:17) in Dominion South improved a little bit but not that much, maybe going from $1 to $0.60 or $0.70. But specifically for Range, if you look at slide 15 in our presentation, it talks about our firm transportation takeaway in 2016 and 2017. And though it increases, it's part of the increase in our transportation and gathering when you look the cycle margins. It increases the cost, but also our basis differential improves, both in 2016 midpoint of around $0.42 and then going out into 2017 when some of other projects come into service, it improves even more, midpoint of about $0.28 to $0.30. So that's just helping the margins.

And then the final part of that, probably just a multifaceted question there, is the transport and gathering into 2017, $1.05 in 2016, what's kind of the trend there? Do you expect more upward pressure on that, or could it stay at that level? Roger S. Manny - Chief Financial Officer & Executive Vice President: I think it's going to be – it's going to move around a little bit, Mike, but it's – over time, again, I know we've said that, but as we continue to build out, that's going to plateau, and eventually it will move down as we start to fully maximize the capacity. But again, the big bump is incremental projects that produce incremental margin, incremental revenue. So we're not too upset about the increase that we had in the fourth quarter and that we've announced for the first quarter.

Got it.

The real key on the transportation per unit cost is, as Ray and Roger have talked about, we're going to be putting more and more volumes on, but you're not going to be spending more dollars on gathering and compression. Therefore, your volumes are going to be able to lower that cost just with the volume changes.

Okay. Ray, switch gears, just a quick one on the Oklahoma assets you have for sale. Can you give us the teaser on this? And just I'm curious how much exposure you've got to the STACK and SCOOP? Thanks. Ray N. Walker - Chief Operating Officer & Executive Vice President: We've got BoA marketing it. It's about 28,000 net acres spread across four counties, about 6.5 million a day of production. The acreage is 100% HBP by all legacy vertical wells, about 6.5 million a day of production, about 80% of that is gas. It's right in the heart of the activity where Devon bought Felix's acreage and where Continental is drilling and Newfield is focused. So we will be receiving the bids soon. And we'll be evaluating the valuations and making a decision here probably by the end of March.

Great. Thanks a lot.

Thank you. Ladies and gentlemen, this concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks. Jeffrey L. Ventura - Chairman, President & Chief Executive Officer: I'd like to close with the announcement that Rodney Waller will be retiring this May. We pretty much appreciate Rodney's contributions over the years, and we wish Rodney the best in his retirement. Rodney has been a committed shareholder since 1988. He has built a strong team and Laith Sando has been promoted to continue as Vice President of Investor Relations. We have great confidence that Laith will do well in his new position and the team will continue to be responsive to your questions. Thanks for participating on the call. If you have additional questions, please follow up with our IR team.

Thank you. This concludes today's conference. Thank you for your participation. You may now disconnect.