Antero Resources Corporation (AR) Q2 2016 Earnings Report, Transcript and Summary

Good day, and welcome to the Antero Resources Second Quarter 2016 Earnings Conference Call and Webcast. All participants will be in listen-only mode. Please note also that this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Senior Vice President of Finance and Head of Investor Relations. Please go ahead, sir. Michael N. Kennedy - Senior Vice President, Finance & Chief Financial Officer: Thank you for joining us for Antero's second quarter 2016 investor conference call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I'd also like to direct you to the homepage of our website at www.anteroresources.com where we've provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would like to first remind you that during this call Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Joining me on the call today are Paul Rady, Chairman and CEO; and Glen Warren, President and CFO. I'll now turn the call over to Glen. Glen C. Warren - President, CFO, Secretary & Director: Thank you, Mike, and thank you to everyone for listening to our call today. In my comments, I'm going to highlight our second quarter financial results including price realizations and EBITDAX margins, touch on the attractive upside we see in an improving commodity price environment and discuss the recent equity offering we completed during the quarter. Paul will then provide a brief update on the recently announced acreage acquisition in the core of the Marcellus, highlight the operational momentum we've maintained through the downturn leading to significant drilling efficiencies and cost improvements and provide additional color around improvement in recoveries that we're achieving. Let's begin with some of the key highlights from the quarter. As we had another fantastic quarter both operationally and financially, production averaged a record 1.762 Bcfe/d for the quarter including over 75,000 barrels a day of liquids. This production record was achieved despite downtime at the Sherwood Processing Plant in West Virginia in late June, which resulted in 7.3 Bcfe of deferred production, averaging approximately 80 million cubic feet a day equivalent of production for the quarter. The downtime was caused by an NGL pipeline slip that was repaired by the end of the quarter. The liquids production during the quarter include 17,000 barrels a day of ethane, which represented a 50% increase compared to the prior quarter, driven by an improvement in the ethane frac spread. Moving on to realized pricing during the quarter. We realized an all-in price of $3.95 per Mcfe including NGLs, oil and hedges, despite the lowest average NYMEX natural gas price recorded for any quarter since 1999 at $1.95 per Mcf. As you can see on slide two of our earnings call presentation titled 2Q 2016 price realizations and EBITDAX margin, we realized an average pre-hedge natural gas price of $1.93 per Mcf and after-hedge price of $4.31 per Mcf. As you can see on the top half of the page, our pre-hedge gas price realization of $1.93 per Mcf was only $0.02 less than the average NYMEX price and $0.35 higher than our next closest peer for the quarter. Our after-hedge gas price realization of $4.31 per Mcf was a $2.36 premium to the average NYMEX price and $1.79 per Mcf higher than our next closest peer for the period, further demonstrating the significant value of our hedge book. On the liquids front, we realized an unhedged C3+ NGL price of $17.08 per barrel or 38% of NYMEX WTI and an ethane price of $8.36 per barrel or $0.20 per gallon. Directing you to the bottom half of the page, you can see how these superior price realizations and hedge gains translate into our peer leading EBITDAX margin. At $1.86 per Mcfe, our EBITDAX margin is $0.81 per Mcfe higher than the next closest peer. During the quarter, we generated $332 million in consolidated EBITDAX. As you can see on slide number three titled highest EBITDAX and margins among peers, despite a decline in NYMEX gas and oil prices of 26% and 21% over the last year respectively, our EBITDAX increased by 24% year-over-year, resulting in $100 million more cash flow than our next closest peer. Detailed on the bottom half of the slide, this resulted in the fifth consecutive quarter in which Antero led the peer group in EBITDAX margins. The ability to consistently generate top tier EBITDAX margins is a function of our differentiated strategy of targeting the best netback pricing by moving our gas production outside of the basin with optimal takeaway, focusing on liquids value uplift and hedging our production, often years in advance. Antero's differentiated strategy offers investors in Appalachia a fairly stark choice. You can either invest in an active core producer like AR, who has already sold over 80% of its forecast production through 2019 at $0.75 per Mcfe above the current strip prices, or you can invest in producers who are partially hedged at lower prices with lower activity levels, less core drilling inventory and take your chances with prices and basis. The next slide really quantifies the strategy. Directing you to slide number four, titled incremental costs drive price realizations, the blue outlined callout box demonstrates how our firm transportation expense of $0.40 per Mcfe enables us to sell our gas at an expected premium realization of $0.14 per Mcf compared to the strip pricing through 2018. Said another way, if you deducted the firm transport costs of $0.40 per Mcfe from our expected realized pricing, we would still achieve a netback of $2.83, which is $0.52 per Mcf higher than the Dominion South index that many of our peers are selling their gas at today. Many peers, of course, also sell at TETCO, which is very comparable pricing to Dominion South. Now moving on to the liquids uptick. We pay approximately $0.60 per Mcfe in all-in processing fuel cost y-grade transport and fractionation costs. And at $52 to $70 WTI range, this translates into $0.71 to $1.18 per Mcfe uplift in price realizations. While the base cost structure may be higher than that of a dry gas-focused producer, we see more upside on the liquids over the medium and longer term and have positioned ourselves accordingly. Directing you to the right half of the slide, AR would realize all-in pre-hedge prices of $4.18 per Mcfe to $4.41 per Mcfe assuming $60 and $70 per barrel WTI prices respectively and that's right on top of the dark green bars. While this strategy of drilling liquids rich gas and locking in the most attractive takeaway in prices while incurring slightly higher cost may differ from many of our peers, the end result comes down to generating the highest margin per Mcfe of production, which we've consistently achieved and expect to continue moving forward. So, if you look at that cash margin, it's about $2, the difference between the total cash costs and that's a pre-hedge all-in price. And you get that for spending about $0.50 on the F&D side, so kind of a 4:1 ratio. Before moving on to discuss our upside in an improving commodity price environment, I wanted to touch briefly on net marketing expenses. During the quarter, we generated $91 million in net marketing revenue and $126 million in marketing expenses. We purchased and sold approximately 500 million cubic feet a day of third-party gas, utilizing excess capacity on the Tennessee Gas Pipeline and capturing an average spread of $0.40 per Mcf. Net marketing expense was ahead of internal expectations of $35 million or $0.22 per Mcfe. Looking forward to the remainder of the year, we are guiding to second half 2016 net marketing expenses of $0.10 per Mcfe to $0.15 per Mcfe. This significant reduction per Mcfe compared to the current quarterly results and a function of a previously announced third-party agreement that went into effect on July 1, 2016 and will continue until the Rover Pipeline is placed in service or December 31, 2018, whichever is later. The third party has the same responsibility for our stranded ANR Pipeline capacity and will pay the demand fees associated with that pipeline. Now moving on to our positioning in a commodity price rebound, particularly on the liquids pricing, I'll direct you to slide number five, titled Largest Core Liquids Rich Drilling Inventory. In the yellow highlighted box, you will notice that pro forma for the pending acreage acquisition, we control an estimated 39% of the NGL reserves in the liquids rich core of the Marcellus and Utica combined, which translates to about 420,000 net for liquids rich acres. In fact, we're currently running 58% of the rigs in the liquids rich core areas in all of Appalachia. A key part of our strategy is positioning ourselves for an NGL price recovery and we believe we're best positioned to capture this upside. Now looking at slide number six, titled NGL Growth and Ethane Optionality. We have guided to 47% NGL production growth in 2016, which is on top of our 117% (11:10) growth in NGL production in 2015. Through the first two quarters of the year, we're well on track to hit this guidance. The NGL production growth guidance assumes a net 10,000 barrels a day of ethane, but we have substantial ethane optionality as well. Assuming a full ethane recovery scenario today, we would be producing over 90,000 net barrels per day of ethane, which gives you a feel for ethane optionality. Before I turn it over to Paul, I'll briefly touch on the equity offering that we completed in June to fund the recently announced pending acreage acquisition and reduce debt. On the base offering, we sold 26.8 million shares of common stock for net proceeds of $753 million. Just recently, we also closed on 3 million additional shares as part of the overallotment option, generating an incremental $85 million. The combined $838 million of net proceeds will be used to fund the acreage acquisition and for repayment of borrowings under our revolver initially. The overall transaction was very well received due to the high quality nature of the acreage as we priced at the tightest spread for any E&P offering over $500 million since the commodity price downturn began in late 2014. With that, I will turn it over to Paul for his comments. Paul M. Rady - Chairman & Chief Executive Officer: Thanks, Glen. In my comments today, I will discuss the significant benefits of maintaining operational momentum through this downturn, provide a brief update on the recent Marcellus core acreage acquisition and finish with the review of our current well economics, which have improved tremendously through continued reductions in drilling costs, efficiencies, higher EURs and improved commodity pricing. As we've mentioned in the past, because of our strong hedge and firm transport book, we've been in a unique position to be able to maintain a significant level of development activity throughout this commodity price downturn. This has enabled us to continue moving up the learning curve as it relates to drilling efficiencies and overall well recoveries. While we cannot predict the future of commodity prices, we can say with conviction that we are operationally a stronger company today than we were before the downturn. As I'll touch on in more detail in my remarks, we have reduced well costs by over 30% over the last 18 months and have increased overall recoveries by 20% or more over that same timeframe. Additionally, our strong balance sheet and financial position throughout the downturn has enabled us to consolidate core acreage and continued a high grade and attractive inventory of highly economic locations. Lastly, as we continue through this commodity price uncertainty, I'll remind you that we are a 100% hedged on expected gas and propane production for the remainder of 2016 and 100% hedged on expected gas production in 2017 at prices that are more than $0.60 higher per Mcfe than the current strip pricing. Now, let me first provide you with an update of our pending core acreage acquisition and strategic rationale. I'll direct you to slide number seven, entitled acquisition update. As outlined on the top of the page, the tag along rights on the acquisition have been exercised adding an incremental 11,500 net acres and approximately 900 Bcf equivalent of unaudited Marcellus 3P reserves to the transaction. That brings the total acquired net acreage to 66,500 net acres, the total 3P reserves to 5.0 Tcf equivalent and total net production of 16 million cubic feet equivalent per day, all for a purchase price of $546 million. Overall, this acquisition will impact 1,060 gross undeveloped locations through either newly added locations, lateral extensions or increased working interests on existing and future wells. What makes this acquisition even more exciting to Antero among the other aspects listed on the slide is the attractive liquids rich well economics associated with the acreage that's consistent with recent Antero well results. With the application of our recent advanced completion techniques, we expect the acquired high-graded core acreage to yield similar consistent results. Pro forma for the announced acquisition, we estimate that we control over 50% of the Southern Rich Gas core, which is outlined in red on the map. This speaks to the substantial liquids rich footprint we continue to build in the southwest Marcellus to drive long-term value creation for our shareholders. Now let's move on to the operational efficiencies and cost reductions that we've achieved over the last 18 months. On slide number eight, entitled proven track record of well cost reductions, AR has reduced its well cost by 34% in the Marcellus over the last 18 months to $0.9 million per 1,000 feet of lateral. The bottom half of the slide illustrates that we've seen similar success in the Utica with well cost totaling $1.0 million per 1,000 feet of lateral or a 33% decline over the last 18 months. Not only did second quarter 2016 well cost represent significant reductions compared to 2014, but Marcellus and Utica well costs represented a 17% and 13% reduction respectively compared to well costs assumed in our year-end 2015 reserves. The reduction in well cost has been a function of reduced service costs, but more importantly, sustainable operational efficiencies. From a service cost perspective, we are really in the driver seat in terms of sustaining the cost reductions, a direct result of being the most active operator with seven rigs and five completion crews running. To further touch on the operational efficiencies, I'll refer you to slide number nine entitled, continuous operating improvement. During the quarter, we set another company record drilling 7,274 feet of lateral in a 24-hour period while staying within a 10-foot zone. The more efficient drilling led to a reduction in spud to rig release drilling days in both the Marcellus and the Utica. In the Marcellus, drilling days have decreased by 48% from 29 days in 2014 to 15 days during the second quarter. In the Utica, drilling days have decreased by 45% from 29 days in 2014 to 16 days in the second quarter. Additionally, stages completed per day in the Marcellus increased by 22% from 3.2 stages per day in 2014 to 3.9 stages per day during the second quarter. In the Utica, stages completed per day increased from 3.2 stages per day in 2014 to 4.4 stages per day in the second quarter, a 38% increase. From a wellhead recovery standpoint, we continue to achieve encouraging results utilizing advanced completion techniques. To provide further clarity, I'll direct you to slide number 10 entitled, advanced completions drive higher EURs. As you can see on this slide, we've normalized 24 wells that have been placed on sales in 2016 and completed with at least 1,500 pounds in profit per foot to time zero. So, we've equalized all these wells to time zero, and those that have had at least a 9,000-foot lateral. We also included the 1.7 Bcf per 1,000 foot type curve used for reserved booking at year-end 2015 and a 2.0 Bcf per 1,000 foot type curve as well. The aggregated red production line is thus far exceeding the 2.0 Bcf per 1,000 type curve, which would represent a 33% increase compared to 2014 and an 18% increase relative to our 1.7 Bcf per 1,000 type curve. While we are still early in the evaluation process, the results are very encouraging. As it relates to well economics, as you'd expect, a 33% reduction in well costs and a 33% increase in EURs has a significant impact on returns and drives very attractive economics on AR's development program. To provide more color on this, I'll direct you to slide number 11 entitled Marcellus upside potential. On this slide, we've provided rates of return in the highly rich gas condensate and highly rich gas regimes of the Marcellus. These regimes represent the areas where we are active today and completing wells with the advanced completion techniques I just discussed. As detailed on the slide, if we are able to consistently develop to deliver the EURs 2.0 Bcf wellhead gas per 1,000 feet of lateral, this translates into rates of return of 77% in the highly rich gas condensate areas and 51% in the highly rich gas area, assuming June 30, 2016 strip pricing. While still very early stage, we have begun pilot testing even higher profit loads with sand volumes upwards of 1,750 pounds to 2,000 pounds per foot and water volumes of 40 barrels to 45 barrels per foot. We believe these higher profit loads have the potential for recoveries of upwards of 2.3 Bcf per 1,000, which would result in pre-tax rates of return of almost 100% in the highly rich gas condensate regime and 66% in the highly rich gas regime. As a reminder, we have almost 2,000 locations in these two areas alone pro forma for the announced acreage acquisition. This provides us with tremendous confidence that we can generate substantial value creation for many years to come. In summary, we've made some of the biggest strides operationally in 2016 since we entered the play in 2008, and have further consolidated the liquids area of the Marcellus. Our business plan, which is focused on low unit cost development, best-in-class realized pricing, peer-leading margins and ongoing consolidation, continues to pay dividends for Antero. Looking ahead, Antero is uniquely positioned for long-term success and will continue to thrive as commodity prices recover. In short, the outlook remains extremely bright for Antero. With that, operator, let's open it up for questions.

We will now begin the question-and-answer session. Our first question comes from Brian Singer of Goldman Sachs. Please go ahead. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning. Glen C. Warren - President, CFO, Secretary & Director: Good morning, Brian. Paul M. Rady - Chairman & Chief Executive Officer: Hi, Brian. Brian Singer - Goldman Sachs & Co.: To the point you made in your comment, natural gas prices are not necessarily the driver given your hedges and FT. So, can you tell us your thoughts based on the extent of your willingness to outspend cash flow and how aggressively you see yourself – or and how aggressively you want to have your balance sheet, where you see investments moving as we go into 2017 and how we should think about that willingness to outspend cash flow. Glen C. Warren - President, CFO, Secretary & Director: Well, Brian. Yeah. This is Glen. Our balance sheet, we expect it to stay in the mid 3s in terms of leverage over the next 12 months to 18 months and then decline over time back into the high 2s just kind of naturally. So, it's something – it's leverage that we're very comfortable with. And in terms of our D&C capital for instance for next year, we expect to be pretty much in line with this year, which this year is $1.3 billion. So, should be in that same neighborhood next year in terms of capital spend for drilling and completions. Brian Singer - Goldman Sachs & Co.: Got it. Great. And then two other small questions. The first is, can you talk to the success that you're having or update us on the success that you're having in off-loading any access to FT and how that that might be being shared with the other party. And then your thoughts on beyond the FT specific portion you addressed in your comments, how the timing of the Rover Pipeline would impact your production trajectory? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. So, in terms of Rover, we project – we've, of course, had plenty of discussions with Energy Transfer. They just announced the other day that they received the final EIS to build Rover. So, now there's a waiting period of approximately 90 days and then construction could potentially begin later this year. Handicapping it, as construction is going to take somewhere between eight months and 12 months, we see Rover being in operation sometime between mid-2017 and the end of 2017. And so, with that, we'll adjust our budget as we get further clarity on that, as to how much Utica versus Marcellus we'll develop. We have currently maxed out our REX capacity at 600 million a day in the Utica. And so that's why we've toned it down for the next eight months or so, and moved more of our capital back to the Marcellus. So, Rover timing will have some effect on where we put the capital. But as we just detailed, we have excellent economics, rates of return and so on in both plays. So, it's great that we have the flexibility to move the capital back and forth. In terms of the FT and offloading it, yes, we've been able to – as part of our agreement with Energy Transfer, they take on our Southbound ANR until Rover is in service or the end of 2018, whichever is first. So, that is 600,000 MMBtu a day. So that's important for us and helps in our reduction of net marketing expenses. Beyond that, as Glenn detailed, we've been buying third-party gas on the order of 500 million cubic feet a day, and we're sharing the margin with those producers. And we see that to continue going forward and that helps offset that marketing expense. Those are some of the bigger ones but we're definitely looking at other opportunities to offset marketing expense across our portfolio. Brian Singer - Goldman Sachs & Co.: Great. Thanks very much. Paul M. Rady - Chairman & Chief Executive Officer: Sure.

Our next question comes from Holly Stewart of Scotia Howard Weil. Please go ahead.

Morning, Paul, Glen and Mike. Paul M. Rady - Chairman & Chief Executive Officer: Good morning. Glen C. Warren - President, CFO, Secretary & Director: Hi, Holly.

First question just on the acquisition, kind of help us think through how that activity on those new properties gets worked in over the next few years. Paul M. Rady - Chairman & Chief Executive Officer: Well, we could divide the acquisition into two parts, the part where the acreage is in and amongst our existing acreage and in and amongst our existing infrastructure, gathering, processing, compression, that will be developed almost immediately over the next 18 months. We have rigs that will include a lot of that acreage within our units. So they are nearby units, where we'll just move the rig over. And then where it's a little further afield where it's in Wetzel County is going to take some time, at least 18 months to begin building our infrastructure to be able to reach that far north. So, it'll be phased in over the next year-and-a-half, two years for the more outlying acreage.

Okay, great. And then, maybe, Glen, on the ethane volumes, just really big ethane volumes really in the second quarter, no change to the guidance that would imply some material changes in the back half of the year. So, is there something we should be thinking about with maybe that occurred in the second quarter or just how we should be thinking about the second half of the year for ethane? Glen C. Warren - President, CFO, Secretary & Director: No. I don't think so. We did not change the guidance, no. But I think you can expect us to exceed that guidance throughout the year. So, the number for the second quarter would not be an unusual number. I think for the rest of the year we just didn't change the guidance there, Holly. So, I would not expect a significant pullback in ethane volumes.

Okay. Great. And then one final one for me if I could. On slide 10, you're showing with the advanced completions you're really outperforming the type curve. I know it's still early, but any thoughts on when you might be updating those curves? Paul M. Rady - Chairman & Chief Executive Officer: Well, certainly on updating the curves and our expectations we get greater confidence, of course, with every well, with every pad and that'll lift our expectations, but as to how we would do lift the reserve bookings more area wide, we're pretty conservative there. And so, one needs quite a bit of production history, probably a year or more to gain confidence and then it'll begin just with direct and diagonal offset type of reserve booking. What we have done, once you have a statistical sampling that covers a much broader area then, we with the reserve auditors can book many of the locations in between. So, it can be a larger uptick, but that's probably a year, year-and-a-half out to upsize the bookings in broad areas. It's going to be on a pad by pad basis for probably the next year. Glen C. Warren - President, CFO, Secretary & Director: And I think just to add to that, reserve bookings are one topic certainly, but the other is, I think, you can assume that our expectation in that red outline that you see on our maps now is to see 2 Bcf per 1,000 that's certainly the target and the expectation going forward, and hopefully it's even better than that as we said.

Got it. Thanks, guys. Paul M. Rady - Chairman & Chief Executive Officer: Thank you.

Our next question comes from Neal Dingmann from SunTrust. Please go ahead.

Good morning, guys. So... Paul M. Rady - Chairman & Chief Executive Officer: Good morning.

May be questions quickly for Glen first or maybe for you, Paul. Just on the outspend, again, obviously, it's translated very quickly into production in future upside. How comfortable are you with kind of when you look into 2017 and exiting that year forward on the outspend? Glen C. Warren - President, CFO, Secretary & Director: Given our rates of return and the fact that leverage is expected to actually decline through the rest of the decade, we're quite comfortable outspending as long as we continue to see stability in natural gas prices and hopefully some recovery again in oil and NGL prices. So, a longer range plan is to outspend over the next few years given the kind of rates of return that we're looking at. And we haven't really modeled in ourselves hitting 2 Bcf per 1,000 or higher in the Marcellus. So, I think if we can consistently do that then the outspend actually shrinks even further, so, time will tell.

No. That just certainly makes sense. And then just two others if I could. Paul, you mentioned on, this new property that you all are building out, some pipe there, what's the timing there and how much you need to build out? I guess, I'm just wondering when you look at Wetzel and Tyler and Doddridge, to me it's quite perspective, obviously, for both Utica and Marcellus, but is that just going to be mostly infrastructure-dependent here in the next several quarters? Paul M. Rady - Chairman & Chief Executive Officer: We're quite well built out already in Doddridge, and pretty well built out in Tyler. So, it's really Wetzel that is more far afield. So, a lot of the infrastructure is already underway for Doddridge and Tyler. And we'll be able to fold that in pretty quickly. But it is Wetzel, and as we were saying, it's probably a year-and-a-half to reach the northern part, maybe two years to reach northern Wetzel and it'll be a phased-in well. We'll build the southern Wetzel first and be developing that and then make the jump across. So, it's going to take some time to get up to northern Wetzel.

Will that be mostly Utica-focused, Paul? Paul M. Rady - Chairman & Chief Executive Officer: No, it'll be mostly Marcellus-focused.

Okay. That's what I thought. And then, just lastly, you guys have had, obviously, great – just we're seeing when you continue to push the proppant, it seems to be more and more just pushing the economics on these wells. How do you see kind of going forward, will you continue to push the proppant loading on a lot of these wells? Paul M. Rady - Chairman & Chief Executive Officer: We will. We've got the pilots we mentioned, 1,750 pounds and 2,000 pounds and corresponding water volumes, and we'll see how those work out. We don't want to juggle too many parameters at once, too many variables, but yeah, we'll test 1,750 pounds and 2,000 pounds and see if that gives us another good bump. And so, right now, I think our standard design is going to be 1,500 pounds with the piloting to go up to at least 2,000 pounds. And we'll probably step beyond that as well over time.

Very good. Thank you all. Paul M. Rady - Chairman & Chief Executive Officer: Thank you. Glen C. Warren - President, CFO, Secretary & Director: Thank you.

Our next call comes from James Sullivan from Alembic Global Advisors. Please go ahead.

Hey. Good morning, guys. Paul M. Rady - Chairman & Chief Executive Officer: Good morning, James.

Just very quick, obviously, you guys highlighted some great deliverability potential on the ethane side. Obviously, looking at the spot market right now, just back under $0.17 a gallon, that's kind of despite the Morgan's Point startup. Do you guys have any sense or can you comment a little bit just on how you see that market evolving over the next 12 months or 18 months. I know that the startup at Morgan's Point seems to be pretty slow, they're not going to really hit capacity till late 2017, but there was a lot of line fill with Mariner and doesn't seem to be much at Morgan's Point. Can you just give us your feel on that? Paul M. Rady - Chairman & Chief Executive Officer: Well, I think, we're optimistic longer term. We all probably read the same reports on the petrochems, the ethane crackers that are being built along the Gulf and the added demand there, call it 400,000 barrels or 500,000 barrels a day over the next one year to two years. So that's going to help, as you mentioned, Morgan's Point. And certainly we've talked with some of the ethane buyers that are shipping out of Morgan's Point to sell directly. So, I think, it will improve, but it's still under stress at $0.17 you're right on the margin whether you want to recover or leave it in the stream. In fact, you probably disregard if not for some cost you definitely be leaving it in the stream.

Okay, great. Thanks for that. Just shifting over then. If I look at to something on the Utica drilling side, if I look at your slide eight from your presentation, you guys driven obviously phenomenal D&C cost reductions. But if I just look at it, it looks like the Utica drilling costs with the four elements drilling and completion between the two basins that have come down the least. Now on the other hand, your drilling days have come down on an order of magnitude same magnitude at the Marcellus, 45% versus 48% I think. Is there another factor that would account for the absolute dollar cost coming down a bit less in the Utica? And I'm thinking here maybe depth or legacy rig costs and if it is the latter legacy rig cost, is there a time when that starts to roll-off and you might get better re-contracted rates? Paul M. Rady - Chairman & Chief Executive Officer: Yeah, there are some legacy costs in there, but our rigs are rolling off in the next six months to 18 months and so that will help. But we haven't had as much, I guess, you'd call it, practice at the Utica. We haven't drilled as many wells. So, a lot of the great efficiencies, the great operating techniques that we're working out in the Marcellus we just haven't done enough of those yet in the Utica. So, do expect that cost can come down further in the Utica, but we just haven't been as active there. As we say fewer rigs drilling there and less capital planned until Rover goes into service, which is a year to a year-and-a-half away. So, it'll be a little bit more subdued in our experimentation.

Okay great. Something to look forward to then. Thanks guys. Appreciate it. Paul M. Rady - Chairman & Chief Executive Officer: Okay. Thank you. Glen C. Warren - President, CFO, Secretary & Director: Thank you.

Our next question comes from Jon Wolff with Jefferies. Please go ahead.

Good morning. Glen C. Warren - President, CFO, Secretary & Director: Hi, Jon. Paul M. Rady - Chairman & Chief Executive Officer: Hi, Jon.

Hey, how are you? Curious, so, Stonewall has sort of a volume transitioned from sending gas north versus going towards TCO, sort of, how much volumes were reallocated? And then if you had any thoughts on why M2 TETCO point, Dominion South point is still so weak given that some volumes have been diverted and production in the basin has fallen? Paul M. Rady - Chairman & Chief Executive Officer: Yes. So let me tackle that second one first. TETCO M2 and Dominion South continue to stand out when you look at indices really across the country. It's really Pennsylvania, Southwest PA and Northeast PA that are in distress whether its Leidy hub or TETCO M3 is Eastern PA. And so there's a lot of gas trying to escape and just not enough straws in the pot in that area. That's a reason why we can buy distressed third-party gas and move it down on our TCO capacity. But I think there's just a lot of gas that's trying to move out of the northeast Marcellus, so it comes around the horn. It comes from Northeast PA and comes down and tries to get out of Eastern PA. The markets are also distressed there...

So possibly some gas that was behind pipe that came on when you might have diverted, I think, several hundred million that were going north towards that direction? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. That's true. And that gets to your second question is, it was several hundred million that we were sending before Stonewall opened, which was last November. Before that, we were moving gas up EQT and Momentum to TETCO and selling into that distressed market. And you can see, today's price, TCO is very close to NYMEX. It's maybe $0.13 off, and so that would be in the $2.60-ish, $2.70 range, whereas TETCO M2 and Dom South are $1.35 to $1.40. So, it makes a big difference obviously, and, so the big picture is still...

How many volumes do you think Stonewall were able to provide you to TCO, sorry, with the expansion? Paul M. Rady - Chairman & Chief Executive Officer: Well. We're moving...

Incrementally. Paul M. Rady - Chairman & Chief Executive Officer: ...more than 1 Bcf a day right now. And so it's going to either to the TCO pool or the TCO based sales contract, so.

All right. Paul M. Rady - Chairman & Chief Executive Officer: So, a lot of it, at least 300-million plus a day that was going to TETCO a few quarters ago is coming into the TCO pricing.

Got it. That's what I was looking for. I don't think you talked about the REX reversal, which I think is still scheduled for towards year-end or early next year? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. That's right. Yeah. That's...

Do you feel good about that? And does that help, because I remember in the last call you said to expect Marcellus to be the driver of growth and Utica to be fairly flat. And does the REX reversal, if it comes on in time, does that change that math or does that allow Utica to grow a little more? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. Well, there's another complication there. So, the REX reversal – REX right now is, westbound is 1.8 Bcf a day and they've just done a short shutdown to get prepared for the increase of another 800 million a day. And that's expected to come on in either the fourth quarter or the first quarter of next year. And so, there will be westbound capacity out of Clarington, for example. And so that's going to help to "drain the pool" of Southwest PA and Eastern Ohio. But the complication for Antero is, we have our Seneca processing plant and the residue gas, of course, comes out of there. But it flows on the Seneca lateral, which is also maxed out at 600 million a day. So really we don't see relief until Rover comes to the Seneca plant. So, others will be able to take advantage of REX westbound once the new capacity is added. But we will still be constrained, because we can't get up to and into the REX lateral or into the REX pipeline. So that won't make a difference for us.

That makes sense. Last one was on – I noticed in the last release that you had some success in laying off some of FT to third parties. Was that the case, and is that an ongoing process for maybe the FT that's less preferred in your mind? Paul M. Rady - Chairman & Chief Executive Officer: Well, there's both. And so the FT that we have remaining, especially in and around the TCO pool area and south to the Gulf, kind of the east side of our FT, that's where we are making good returns on buying the distressed third-party gas from Southwest PA and moving it through either to the TCO pool or to the Gulf and offsetting FT costs and making a margin on that. So, we haven't let go of that, and that's good and that's desirable. And then, as I mentioned, a big amount is the FT that under the pre-negotiated agreement with Energy Transfer, which we've had for at least a year-and-a-half, as we signed up for Rover, it was the agreement that they'd take over ANR Southbound until – beginning July 1. So, last month, July 1, 2016 until Rover is in service, which is – that's a big factor in reduction of FT costs.

Understood. Certainly helpful. Thanks. Paul M. Rady - Chairman & Chief Executive Officer: Okay. Thank you.

Our next question comes from David Deckelbaum from KeyBanc. Please go ahead. Paul M. Rady - Chairman & Chief Executive Officer: Hi, David.

Good morning, Paul. Good morning. How are you? Thanks for taking my questions. Paul M. Rady - Chairman & Chief Executive Officer: Sure.

I'm just curious to follow up on the M&A. You guys had successful bolt-ons and you've pointed out that you now control kind of a majority of that southwest Marcellus core area. You also talked about the build out required in Wetzel. I guess, in terms of the opportunity there, how much more opportunity is there to sort of fold in acreage or pick up acreage that's sort of already set along your Midstream facilities there? And is there a strong desire to pursue things like that now, or getting back, I guess, to your earlier conversations of comfortable growing production, you had the large hedge book, outspending cash flow keeping the balance sheet clean. I guess, if you're able to pull off similar deals like the one that we just saw, should we expect you to pursue those pretty aggressively this year? Glen C. Warren - President, CFO, Secretary & Director: Well, there's the base load leasing that that's a continuing effort, and so the acres that we are acquiring in this pending acquisition, it's not completely blocked up. So there is an effort to continue to block that up, so that's one aspect. And then, yes, we are continuing to monitor and engage around additional consolidation, and time will tell as to whether or not more of that gets done in a material fashion or not. It's just kind of hard to say, but we do still have an appetite for that. And while we're not ramping up the rig count dramatically, with as Paul mentioned earlier and we're kind of taking a moderate approach to this sort of adding one rig driven by that southwestern acquisition here next year. I think you're going to see them over time as we expand the platform with a larger and larger resource base and activities going to expand commensurate with that. We're not looking to just add more locations to extend sort of the life of the drilling program. It's really more about building a bigger company and building it more rapidly, but keep in leverage and check. So there are lots of factors that you take into consideration when you're negotiating these deals, but there still are some attractive opportunities out there.

That's helpful. And then the last one for me, and maybe it's a little bit of an oddball question, but I suppose that we go into the end of the year here and we do see supply declines persisting demand pickup on the gas side, you see Henry Hub pricing spiking above where your hedge book is in 2017, you're 100% hedged. And in that sort of framework, is that just become as we get closer to where your hedge book is, is that just a trigger to increase production further? Or how do you guys think about capturing potential near-term spikes in the market that might persist for 12 months or so? Paul M. Rady - Chairman & Chief Executive Officer: Yeah, I think that's a good way to think about it. It'll be a measured approach, but if we were to see sustained $4 gas then that would certainly, and maybe even below that, stimulate more drilling beyond what we've talked about in our D&C budget similar to this year. We could certainly increase that fairly easily. We have lots and lots of inventory to drill. So, that's an opportunity.

Thanks, guys. Paul M. Rady - Chairman & Chief Executive Officer: Thanks, David. Glen C. Warren - President, CFO, Secretary & Director: Thank you.

Our next question comes from Drew Venker from Morgan Stanley. Please go ahead. Drew E. Venker - Morgan Stanley & Co. LLC: Good morning, everyone. Paul M. Rady - Chairman & Chief Executive Officer: Good morning. Glen C. Warren - President, CFO, Secretary & Director: Good morning. Drew E. Venker - Morgan Stanley & Co. LLC: I just wanted to ask couple questions about the longer term planning. You guys have been drilling longer laterals than a lot of your peers for quite some time now in Appalachia. And we've seen some industry test that are actually much, much longer closer to 20,000 feet drilled successfully. Do you feel like that is something that's technically feasible for you or that would be practical to implement on a widespread basis, given, I guess, physical limitations or acreage lease geometry, things like that? Paul M. Rady - Chairman & Chief Executive Officer: That's a good question. The longest we've drilled so far is out to 14,000 feet sideways, and we did that pretty trouble-free. We know of the wells over in the Utica that have gone out towards that 20,000 feet. The good news for us is, we don't have the acreage limitations where we need to go to 20,000 feet if something is unreachable. So, would that be a money saver versus a concentration problem? I think you'd say that if you go extra long like that, now we haven't junked any wellbores in a long time, but if something went wrong on the mechanical side is that higher risk. So, we are going longer and longer. We're in the mid-9,000s feet these days as an average lateral of 9,000-plus feet. We feel quite comfortable and have a lot on the schedule that are in the 11,000 feet to 14,000 feet range. And we'll just see, we haven't completed our 14,000 footer yet. Expected to not be a problem, but the theoretical limitation could be, can you break down the very further stages out at the toe of the wellbore, do you have enough horsepower to overcome friction loss and get into those far zones. So, we think we can. We've got the numbers that say we can, but we'll want to do that before we start thinking about that 20,000 footer, the 18,000 foot. But as I say, the good news is, we can reach about everything we have with the shorter laterals than that. So, it have to be a good cost savings to balance the higher risk. Drew E. Venker - Morgan Stanley & Co. LLC: Okay. Well, so, it sounds like it'd be more of a, I mean, somewhat aggressive but somewhat measured approach to pushing those out longer than just some rapid jump to 20,000 foot. Paul M. Rady - Chairman & Chief Executive Officer: Yeah. Drew E. Venker - Morgan Stanley & Co. LLC: Okay. Paul M. Rady - Chairman & Chief Executive Officer: Yeah. Definitely. Drew E. Venker - Morgan Stanley & Co. LLC: And then on the higher proppant loading the better performance you've seen. I just want to make sure I understood the answer to that question, earlier on the call. If we continue to see similar performance in those higher proppant loadings, would you spend that additional cash flow or let that cash flow accrue to the balance sheet? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. So that might've been, I think Glen might have answered that one. Glen C. Warren - President, CFO, Secretary & Director: I think that's really just a function of well economics, right. If it makes sense to spend the capital on a well to load it with more proppant than you do it right and the balance sheet sort of a different decision as to how you run that, but I don't expect us to change our views on the balance sheet. Paul M. Rady - Chairman & Chief Executive Officer: Yeah, that's right. If it makes sense on a well by well basis and where is the point, like in any play, where is the point of diminishing returns and does 2,000 pounds give you a nice bump, 2,000 pounds per foot, but 2,500 pounds it's not worth the extra cost that's what we all work our way up to kind of the edge of the peak and see where that is. There are many others in the industry including in the Utica and even in the Marcellus where they've gone to 2,500 pounds plus and we ourselves in our do deep Utica test were up above that above 2,500 pounds per foot. So, I do believe it's feasible it's just will it give you the economic return. Drew E. Venker - Morgan Stanley & Co. LLC: Okay. Thanks everyone. See you soon. Glen C. Warren - President, CFO, Secretary & Director: Thank you, Drew. Paul M. Rady - Chairman & Chief Executive Officer: Thanks, Drew.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Michael Kennedy for any closing remarks. Michael N. Kennedy - Senior Vice President, Finance & Chief Financial Officer: Thank you for joining us on the call today. If you have any further questions, please feel free to contact us. Thanks again.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.