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Edited Transcript of AR earnings conference call or presentation 1-Mar-17 4:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Antero Resources Corp Earnings Call

Denver Mar 1, 2017 (Thomson StreetEvents) -- Edited Transcript of Antero Resources Corp earnings conference call or presentation Wednesday, March 1, 2017 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Michael Kennedy

Antero Resources Corporation - VP of Finance and Head of IR

* Paul Rady

Antero Resources Corporation - Chairman and CEO

* Glen Warren

Antero Resources Corporation - President and CFO

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Conference Call Participants

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* Neal Dingmann

SunTrust Robinson Humphrey - Analyst

* David Deckelbaum

KeyBanc Capital Markets - Analyst

* Holly Stewart

Scotia Howard Weil - Analyst

* James Sullivan

Alembic Global Advisers - Analyst

* Brian Singer

Goldman Sachs - Analyst

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Presentation

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Operator [1]

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Good day and welcome to the Antero Resources fourth-quarter 2016 earnings call presentation.

(Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President of Finance and Head of Investor Relations.

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Michael Kennedy, Antero Resources Corporation - VP of Finance and Head of IR [2]

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Thank you for joining us for Antero's fourth quarter and full-year 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 would also like to direct you to the homepage of our website, at www.anteroresources.com, where we have 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 will now turn the call over to Paul.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [3]

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Thanks, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to first provide a recap of our consolidation efforts within the basin in 2016; secondly, review our overall development program throughout the year, including some of the key encouraging pad results; and then thirdly, discuss cost efficiencies that we achieved in 2016.

Glen will then highlight our third quarter and full-year financial results, including, first of all, price realization, secondly, capital efficiency gains, and thirdly, EBITDAX margins. He will then provide a brief discussion on a couple of the recent NGL infrastructure announcements and the impact those announcements will have on our business. Lastly, he will touch on our long-term targets and outlook moving forward.

First, let's discuss Antero's 2016 acquisition activity and our efforts to consolidate the Appalachian basin. We are the most active operator in the basin. We have a strong balance sheet and the largest contiguous acreage position in the core of the Marcellus and the Utica. We are, therefore, extremely well positioned to be a leading consolidator in these two plays.

On slide number 2, entitled A Leading Consolidator in Appalachia, you can see the acreage we acquired in the Marcellus throughout 2016, highlighted in green, which is shown in and amongst our existing acreage in yellow. In total, we acquired approximately 74,000 net acres in the core of the Marcellus and the Utica shale plays in 2016, including 64,000 net acres in the Marcellus, which is highlighted on the map.

In addition to our consolidation efforts, I would also like to take the opportunity to point out a number of notable pads where we implemented advanced completion techniques in 2016 and which are now delivering some strong EUR results. One of our recently completed pads that I'll highlight is a 10-well Marcellus pad located in our highly rich gas area in West Virginia.

This was significant, as it represents one of our largest producing pads ever placed to sales, with a combined 30-day rate of 200 million cubic feet equivalent per day and an average process EUR of 2.6 Bcf equivalent per thousand feet of lateral, assuming full ethane rejection. We estimate that the 10 wells on the pad will generate an average IRR of 100% and pay out in 1.7 years, assuming current strip pricing. You'll also notice that each of the highlighted pads on the slide were completed with 1,500 pounds to 1,700 pounds of proppant per foot and are supporting average wellhead EURs at or above the 2.0 Bcf per thousand foot of lateral type curve.

Given the location of this acquired leasehold, we feel very good about our ability to achieve similar results on the nearby acquired acreage, as well as on our existing surrounding acreage. Importantly, consolidation will enable us to continue to improve our drilling completion, capital efficiency, and drill longer laterals and more wells per pad.

Lastly, the vast majority of the acquired acreage is undedicated to third-party midstream service providers. This provides Antero Midstream with additional organic growth opportunities and the ability to optimize existing infrastructure.

Now on to the 2016 development program, we executed our 2016 development program ahead of plan and under budget, while growing our production 24% year-over-year, including 62% liquids production growth, as compared to 2015. We completed and placed online 120 wells during 2016, including 88 in the Marcellus and 40 in the Utica.

By completing our 2016 plan ahead of schedule and under budget, we were able to accelerate 18 wells into the fourth quarter of 2016 without a change to our 2016 drilling completion budget of $1.3 billion. This was primarily a function of the drilling efficiencies and cost reductions achieved in 2016.

On the cost front, we continued to drive down drilling and completion costs through both our operational efficiencies and service cost reductions, as highlighted on slide number 3 entitled, Continuous Operating Improvement. By the fourth quarter of 2016, we had reduced Marcellus average drilling days from 24 days in 2015 to 12 days and increased our completion stages per day from 3.5 stages per day in 2015 to 4.0 stages.

Similarly, in the Ohio Utica, by the fourth quarter of 2016, we had reduced our average drilling days from 31 days in 2015 to 13 days and increased our completion stages per day by 62%, from 3.7 stages per day in 2015 to 6.0 stages per day. These operational improvements, combined with service cost reductions, resulted in a nearly 30% improvement in fourth quarter 2016 well costs relative to 2015 costs, both in the Marcellus and the Ohio Utica.

In combination with the reduction in well costs, we also achieved significant productivity gains in 2015. To help provide more color, I'll turn your attention to slide number 4, called Improved Productivity Drives Lower F&D Costs. As illustrated on this slide, the key operational shift during 2016 was to increase proppant and water used per foot in each completion.

In the Marcellus, we increased the proppant and water used per foot from approximately 1,200 pounds and 33 barrels in 2015 to 1,500 pounds in early to mid-2016, and then to 2,000 pounds and 46 barrels in the fourth quarter of 2016. The increase to 1,500 pounds per foot resulted in a nearly 26% increase in the average EUR per thousand foot of lateral in the Marcellus to 2.4 Bcf equivalent per thousand, assuming ethane rejection. When you combine the reduced well costs with this increased productivity, the result is a significant reduction in overall fourth quarter 2016 F&D costs to $0.41 per Mcfe in the Marcellus and $0.68 per Mcfe in the Utica.

Looking ahead to 2017, we are reiterating our drilling and completion capital budget of $1.3 billion. We have in place long-term contracts for both completion crews and drilling rigs, and we are continuing to see efficiency gains. Therefore, we do not expect any meaningful increase to well costs in 2017.

On the completions front, we expect to continue testing higher proppant loads in 2017. As illustrated on slide 5, entitled Marcellus Completion Evolution for Our 2017 Development Plan, we expect to utilize 1,750 to 2,000 pounds per lateral foot for the majority of our program. And we'll also conduct a handful of pilots at 2,500 pounds per foot throughout the year.

I don't want to jump around too much and confuse you, but if you refer back to slide number 2, you can see that we are observing encouraging early results from the higher proppant loads in the 2.5 to 2.9 Bcfe per thousand foot range, assuming ethane rejection. Ethane recovery takes those EURs to the 3.2 Bcf to 3.7 Bcf equivalent per thousand range.

Before I turn it over to Glen, let me just quickly recap 2016 from an operational perspective. During 2016, through the strategic acreage acquisitions I touched on earlier, we increased our core drilling inventory to over 3,400 locations with an average lateral length of 8,100 feet. This is by far the largest core drilling inventory in the southwestern core of the Marcellus and Utica shale plays.

We reduced well costs nearly 30% in both the Marcellus and Utica and improved overall recoveries in the Marcellus by 36%. The increased recoveries resulted in production growth of 24% during the year, which beat our original 2016 production guidance by 8%. With that, I'll now turn it over to Glen for his comments.

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Glen Warren, Antero Resources Corporation - President and CFO [4]

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Thanks, Paul. Let me begin with some of the key highlights from the quarter and the year. Protection averaged a record 1.99 Bcfe per day, or essentially 2 Bcfe a day for the quarter, a 6% quarter-over-quarter increase, including nearly 87,000 barrels of liquids. Liquids production included 5,000 barrels a day of oil and just over 81,000 barrels a day of NGLs, representing a 7% increase from the prior quarter, as Antero remains the largest NGL producer in Appalachia. This production out performance continues to be driven by operational improvements particularly associated with the advanced completions that were implemented in 2016, which Paul touched on in his remarks.

Moving on to realized pricing during the fourth quarter, we achieved outstanding results for both realized gas and liquids pricing. We realized a $0.07 premium to NYMEX Henry Hub, or $3.05 per Mcf before hedges on our gas production during the quarter, which was $0.52 higher than our next closest peer and $0.78 per Mcfe higher than the peer average. This further validates the strategic advantage of our extensive firm transportation portfolio, enabling us to move virtually all of our gas away from unfavorable local Appalachian indices.

In fact, for full year 2016, we were able to achieve a $0.04 per Mcf premium to NYMEX Henry Hub, which was at the higher end of our guidance of neutral to $0.05 premium. We realized a natural gas hedge gain of $187 million during the fourth quarter, or $1.38 per Mcf of gas produced, and $957 million for the full year, or $1.89 per Mcf of gas produced during the year. Moving forward, we believe our firm transport and hedge book will continue to be competitive advantages for Antero, as uncertainty around both Northeast basis differentials and overall gas pricing is likely to continue.

As a reminder, for 2017 and 2018, we are 100% hedged on our expected gas production at very high levels, $3.63 per Mcf for 2017 and $3.91 per Mcf for 2018. In fact, through the end of the decade, we are 85% hedged versus target gas production for Antero at $3.73 per MMBTU. That's an $0.82 per MMBTU premium to the current strip, almost a $1.00 premium to the current strip.

As it relates to liquids pricing, we realized an unhedged C3+ NGL price of $25.22 per barrel during the fourth quarter, or 51% of NYMEX WTI, and an ethane price of $0.22 per gallon, or $9.36 per barrel, in the Northeast. The C3+ NGL pricing of 51% of WTI during the quarter resulted in realized pricing equal to 43% of WTI for the full year, which was well above our 2016 guidance of 35% to 45% of WTI.

The improvement in realized pricing was primarily driven by the strengthening of Mont Belvieu pricing relative to WTI, with local differentials slightly better than the prior year. This strengthening in Mont Belvieu pricing was primarily a result of increased demand for propane and butane, as propane exports rose to the 1 million barrels a day range.

During the quarter, we generated $476 million in consolidated EBITDAX, a company record. Detailed on slide number 6, titled Highest EBITDAX and Margins Among Peers, our EBITDAX increased by 55% year-over-year and was almost $100 million higher than our next closest peer. Our EBITDAX margin was $2.31 per Mcfe after adjusting for the non-controlling interest in Antero Midstream, or $0.47 per Mcfe higher than that of our next closest peer. This is a further testament to our integrated business strategy, which includes best quality rock, firm transport to favorable price indices, selling gas forward at fixed prices, and the highest exposure to liquids pricing upside in Appalachia.

At the end of the day, the E&P business comes down to cash generation and real cash rates of return, and Antero's excelled in those areas quarter after quarter, as you can see. Continuing on the liquids topic, I wanted to provide a few thoughts as it relates to recent NGL infrastructure announcements, our liquids rich exposure and how that translates into increased cash flow as our liquids production growth continues.

Starting on the NGL infrastructure and our control of the liquids rich resource base in Appalachia, I'll direct you to slide number 7. As outlined in the pie chart in the middle of the bottom part of this slide, based on our detailed technical analysis, Antero holds 41% of the undrilled core liquids rich locations in Appalachia. This provides us with a tremendous leverage and visibility when it comes to the NGL infrastructure buildout in the play.

You can see in the lower right on slide number 7 that our acreage position is well connected to significant NGL processing fractionation in key long haul transportation projects that move our product to market. Antero Midstream, which we own a 59% interest in, recently announced a joint venture with MarkWest related to the buildout of future processing and fractionation facilities. This was very important to Antero Resources, as it provides us with tremendous clarity and certainty around the next 11 Antero-dedicated processing plants, or 2.2 Bcf a day of processing capacity in the Marcellus.

Given our long-term growth targets, it's essential that we are able to secure access to and some control over the timing of future processing and fractionation infrastructure. Continuing on this topic, Sunoco Logistics recently announced that it has received the permits needed to proceed with the construction of Mariner East II. Upon completion of ME II, expected in the third quarter of this year, Antero will be able to minimize expensive rail transport to Mont Belvieu and other domestic NGL markets and move our NGLs by pipeline to markets and on to export markets. Antero is an anchor shipper on ME II, with a 61,500 barrel a day commitment for propane, butane and ethane.

Moving on to the pricing outlook for liquids, I'll point you to slide number 8, titled A Rising Liquids Price Environment. On this slide, you can see the expected improvement in Mont Belvieu NGL pricing, shaded in green, as well as our realized C3+ NGL pricing in 2015 and 2016, which is shaded in yellow. Importantly, we expect this trend to continue in 2017, and as a result, we've raised our guidance, which previously was 45% to 50% of WTI, to now 50% to 55% of WTI for 2017.

This increased C3+ NGL price realization guidance results in an incremental $65 million to $70 million of unhedged EBITDAX in 2017, based on our 2017 C3+ NGL production guidance of 65,000 barrels to 70,000 barrels per day. Once Mariner East II is placed in service, we expect further improvement in NGL netback pricing, resulting in C3+ NGL price realizations of 55% to 65% of WTI in 2018.

It is important to note the increased 2017 guidance and 2018 target pricing included in this slide were simply based on current strip pricing and a blended C3+ NGL barrel for a $12.25 average BTU location. We have not assumed any incremental upside from an improvement in oil prices, further strengthening of Mont Belvieu NGL prices for local differentials.

In addition to a rising liquids price environment, our significant liquids rich inventory enables us to achieve tremendous growth in our liquids production. As shown on slide number 9, titled Rapidly Growing NGL Production, we have increased our NGL production by 93% on a compounded annual growth rate since 2014 and expect to grow to around 150,000 barrels per day by 2020.

Moving on to slide number 10, when you combine the rising liquids price environment with this top-tier liquids production growth, you can really see the exposure Antero has to NGLs and the incremental impact of liquids pricing and production on our future EBITDAX. To help orient you to this page, I'll point you to the yellow line on the chart to the right. This line represents the expected incremental EBITDAX above 2016 levels, assuming $55.00 oil and realized C3+ NCL pricing of 52.5% of WTI.

For example, the red circled number of $332 million represents the incremental unhedged EBITDAX attributable to liquids production that we would achieve in 2017 relative to 2016. The increase is driven by incremental NGL production above 2016 levels and expected improved NGL pricing above 2016 pricing. The green and blue lines represent incremental EBITDAX at additional pricing scenarios, assuming our targeted NGL production levels through 2020.

So to summarize our NGL story, we are the largest NGL producer in Appalachia today and control over 40% of the undrilled core liquids rich locations. We are significantly interconnected to key NGL infrastructure through the recently announced joint venture between Antero Midstream and MarkWest and our commitment to Mariner East II. With a backdrop of rising liquids prices and continued growth in liquids production, we are very well positioned to capitalize on the strong fundamentals and substantially grow our cash flow over the next several years.

Before I finish up, I wanted to briefly discuss our future outlook through the end of the decade. I'll direct you to slide number 11, titled 2017 Guidance and Long-term Outlook. We plan to grow production by 20% to 25% over 2016 guidance, to 2.2 Bcfe per day in 2017, while targeting annual production growth of 20% to 22% thereafter through 2020.

Also, notice the red lines and numbers on the production bars that display the high volume and price level of our hedges, particularly through the 2017 to 2019 period. We expect to achieve this growth while maintaining a drilling completion budget within consolidated cash flow from operations through the year 2020.

Slide number 12, entitled Significant Cash Flow Growth Drives Declining Leverage Profile, demonstrates that as our asset base further matures and our cash flow continues to grow, as you can see in the yellow bars here, we also expect our overall leverage to decline into the mid-2s by next year and beyond, and that's the green sweeping line that you see there.

Now finishing up, on slide number 13, entitled Capital Efficiency Driving Cash Flow Growth, this illustrates how after several years of outspending to build a production base in the business, D&C capital spending is now in line with cash flow. We believe that this marks an inflection point for Antero. The future is quite bright.

With that, I'll turn over the call back over to the operator. Thank you.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

And the first question is from Neal Dingmann with SunTrust.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [2]

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Good morning, guys. Say, could I go right to and dig in on that 10-well pad, Marcellus pad you all mentioned that had that exceptional 1.7 EUR cash on cash you mentioned on the longer laterals and the sand. I'm just wondering on that one, or in that area, location wise, is there still, if you could try and give me some color, is there a lot of acreage that fits that parameters on those 9,000 to 10,000, or 9,000- to 11,000-foot laterals in that same vicinity?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [3]

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Hi, Neal. Yes, absolutely. There's a lot of locations through there we're pretty solid yellow for many miles and it fit in terms of BTU, yield and pressure. So should have many, many more locations like that.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [4]

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And then on those, you mentioned what that cash on cash, does that assume some inflation on there and is that the well that you have locked in about 70% of your costs in order to achieve that phenomenal cash on cash payout?

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Glen Warren, Antero Resources Corporation - President and CFO [5]

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Yes, that cash on cash payout, that's specific to that pad. So those costs are already all spent, of course. But we do not have any acceleration built into our, in our service costs in the budget for this year. We can hit in that in greater detail, if you like. But we have 90% of our drilling rigs and completion crews under contract this year and about 66% in 2018. You can see that on slide 20 in our website presentation, for March. And within those completion contracts, people are concerned about sand costs and all, we have escalators built in there, but they're tied to things like PPI and CPI and labor indices and some of the sand contracts have an oil index escalator if oil prices go up. But other than that, we're not going to be subject to spot sand prices with those completion crews. It's pretty well tied down to various indices.

So for that reason, we've not built any escalation in service costs into our budget for this year. Plus, we're seeing lots of efficiencies continue in both the Marcellus and the Utica, as you can see. We don't think that's going to stop. And thirdly, the EURs are continuing to improve, as well. So we're pretty comfortable with that. We didn't chase the service cost down last year by lowering our budget. We use our contracted numbers and our AFEs.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [6]

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And then last one, if I could, just on the NGLs, you guys are doing, obviously, a phenomenal job with the realizations there. What is the hedge market a year or two, three out? Is that market become much more fluid than it once was? Are you able to continue to lock in these great realizations, I guess is what I'm asking?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [7]

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Yes, the hedge market is there for at least two, maybe three years out. One can hedge ethane, propane, the butanes, if one wants to. Butane is a little less liquid. I will emphasize, in some of our presentations, we blend in the gas and the liquids hedges together. And then it comes out to 60% or so. But in reality, the detail is that we're 100% hedged on gas and quite unhedged on all of our liquids. We are about 75% hedged this year on propane and then unhedged for cal 2018 beyond. And the same with the other products. So yes, there are markets out there where we can hedge, and we will be adding hedges. But right now we see upside in liquids. We see it because of increasing demand, as well as improving infrastructure. So we will be hedging as we go through time. But we're quite well exposed to the upside that we're seeing in liquids.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [8]

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Very good. Paul, Glen, thanks. Great quarter.

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Glen Warren, Antero Resources Corporation - President and CFO [9]

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Thank you, Neal.

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Operator [10]

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Our next question comes from David Deckelbaum with KeyBanc.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [11]

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Good morning, everyone. Thanks, Paul and Glen, for taking my questions.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [12]

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Hi, David.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [13]

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I was just curious to ask, and can you guys give us some color on how you're thinking about ramping your volumes into Rover? And I kind of see this split out that you guys have allocated right now in the Utica for dry locations versus rich gas, which seems to be more rich gas oriented right now, which I imagine is more IRR driven. Is there any thought around a little but more aggressive activity in the drier gas window of the Utica in preparation for a Rover startup?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [14]

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Yes, we're definitely, of course, looking forward to the rover startup. The announced date is July. And so we're prepared to begin filling it as soon as it opens. We might risk that a little bit, or at least we're prepared if it opens later, but expect it to be there in July. We do have a pretty good split between Utica dry gas and Marcellus rich. At the current time, the Marcellus rich gas does have better economics than the Utica dry, but we're making great progress on that Utica dry, really getting well cost down there.

We will be juggling back and forth our CapEx budget between each of the plays. But as we're rapidly building out our processing complex at Sherwood, but do have to time the capital spending on the Marcellus side, tie that all into liquids infrastructure, too. So there'll be some adjusting back-and-forth for Rover. But it needs to match all of our other FT and processing.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [15]

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I appreciate that. Then my other question is, you guys highlight the excess cash that you anticipate generating. You're fairly highly hedged, obviously, out quite a number of years now. So it's fair to say it looks like the program is well covered. Should we be thinking about the uses excess cash in your long-term program to continue consolidating the Appalachian area, or are you starting to look outside the basin, just given that you highlight that you have 40%, 50% of the undrilled locations in the liquids rich core there?

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Glen Warren, Antero Resources Corporation - President and CFO [16]

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Yes, consolidation is certainly still on our minds and we'll continue to consolidate. And so that's one use of the cash. And if there's anything significant there, we'd think beyond just cash flow.

The other note is, we're talking about consolidated cash flow from operations relative to D&C. And we're pretty well covered there, but we do have other spending, along the lines of Midstream spending, because we're giving you a consolidated number there. So I'm not completely at the point of throwing off free cash flow yet over the next few years. We'll be continuing to invest in the Midstream business.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [17]

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All right. Thanks, guys.

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Glen Warren, Antero Resources Corporation - President and CFO [18]

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Thank you.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [19]

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Thank you.

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Operator [20]

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Our next question comes from Holly Stewart with Scotia Howard Weil.

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Holly Stewart, Scotia Howard Weil - Analyst [21]

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Good morning, gentlemen.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [22]

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Good morning.

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Holly Stewart, Scotia Howard Weil - Analyst [23]

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Maybe thinking through slide 10 a little bit, with just the C3+ uplift, maybe taking it a step further, what are your thoughts right now on ethane extraction versus rejection, and then what are your constraints there, if any, I see the ethane guidance for 2017?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [24]

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Well, we, of course, have, if you look at our 3P reserves, we've got well over 1 billion barrels of ethane. And so we have a lot. We will be supporting local markets. We've talked about that, crackers and such. But right now we're recovering in the low to mid-20,000 barrel a day range of ethane and then the rest we're rejecting, leaving in the stream, just because of the ethane economics. All in, so not sub costs, but for new costs, new tariffs and so on, we need to be in the mid-30s in ethane, $0.35 plus a gallon, in order to pay to extract the ethane and ship it to Belvieu. And right now, the futures curve does begin to go out there. It's, in the near term, it's $0.28, $0.29 a gallon and gets out into the $0.34 range. So we're seeing some uplift there and getting close.

What we've been doing is, as I say, leaving it in the stream as we supply to crackers and to export. Those have a mix of gas plus, plus an upside, a Belvieu upside. So we get pretty good prices that are little bit different than just a straight extraction tariff and sell at Belvieu. So we'll be extracting more. Our DF right now at Sherwood is for 40,000 a day. MarkWest will build another one for us, another 20,000 barrel a day, at least, as we go forward, as we prepare for some of the markets, local markets, as well as the good news at Mariner East II is that we'll be exporting ethane to Borealis, as soon as that opens, for another 11,000 barrels a day, and we'll be open for business there on ethane for more international exports. And again, that pricing structure is such that it does pay to recover and we get a good floor, plus an upside as liquids rise.

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Holly Stewart, Scotia Howard Weil - Analyst [25]

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Perfect. And then Paul, maybe a follow-up to that. It sounds like ME II is at least -- or ME II X -- is at least going to move forward, at this point. Any thoughts on a commitment to that project at this time?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [26]

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Well, we're of course pleased that ME II is going forward, and we believe that it will be in service by the fall. We're glad ME II X can go forward, as well, and that just opens up opportunities for us. We haven't thought yet about committing more to ME II X, but we certainly would with the right pricing and the right international markets developing.

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Holly Stewart, Scotia Howard Weil - Analyst [27]

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Okay. And then maybe just a quick modeling one, if I could. Any lumpiness to think about in terms of the quarterly production volume cadence?

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Glen Warren, Antero Resources Corporation - President and CFO [28]

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No, I think it should be fairly steady throughout the year, Holly. We expect to see continuing ramp up. I wouldn't say it would be particularly lumpy. I think it's a fairly steady completion schedule throughout the year. We're watching Rover closely. And I think once we see the spades in the ground, we may want to accelerate some of the ducts that we were going to carry in the Utica into next year. We were planning to finish this year with about 30 ducts, expecting Rover to potentially be end of 2018. So I think if that does come to fruition and they're actually laying pipe, then you may see some acceleration there of [docs] bringing more completions into the third and fourth quarter in the Utica. But that's the only thing I can think of right now. It's pretty steady.

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Holly Stewart, Scotia Howard Weil - Analyst [29]

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Okay. That's helpful. Thank you guys.

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Glen Warren, Antero Resources Corporation - President and CFO [30]

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Thank you.

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Operator [31]

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And our next question is from James Sullivan with Alembic Global.

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James Sullivan, Alembic Global Advisers - Analyst [32]

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Good morning, guys. Thanks for taking the questions. If I could just ask you a little bit again, marketing, on your marketing guidance, once you guys see the ED is spades in the ground, so they're over, do you guys have a plan for setting up that A&R segment that you're going to pick back up from them, and is that any anticipated increased marketing expense in the guidance there?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [33]

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So as Rover and some of the expansions go into the Mishkan Chicago area, so that would be Rover and others that goes to Defiance, if there is a, you know the A&R capacity is bidirectional, and so we'll be able to, if prices are better in the Gulf, then we'll be able to move our own gas, as well as any excess gas, any build up in the Mishkan Chicago markets to the Gulf. So that will be the early stage. And then as we fill up Rover ourselves, then expect to probably move that down A&R and capture any premium in the Gulf, and also just supply the LNG projects that we are producers for, such as Sabine Pass.

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James Sullivan, Alembic Global Advisers - Analyst [34]

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Okay. So the idea would be that picking back up that FT from the Rover team there, you'd be able to pick up any excess gas, just pick it up from the Midwest, rather than from Appalachia?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [35]

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Yes, that's right, that A&R goes from Rex Zone 3 from Shelby, Indiana and also Defiance, it goes south to the Gulf. So that will be third party plus Antero gas. And yes, we will contractually, Energy Transfer turns that back over to us, as it becomes in service to the Seneca complex in Ohio.

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James Sullivan, Alembic Global Advisers - Analyst [36]

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And then lastly, could you guys, just going back to the liquids for a second, could you comment on any particular market strength in the Northeast for propane and to what extent that impacted your, the obviously impressive C3+ realizations that you had in the quarter, and any sense you have about how durable that strength is going to be?

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Glen Warren, Antero Resources Corporation - President and CFO [37]

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No, I think the demand in the Northeast is fairly steady, the local demand. Rail rates have come down quite a bit, which has helped those differentials for railing products in the interim between now and the startup of ME II. But once ME II comes online, you have quite a takeaway option there. They're going to have 275,000 barrels a day of capacity on that pipe going to market and enabling export there. So we feel pretty good about that whole scenario. That's why we were bullish on raising the guidance for this year for NGL pricing relative to WTI.

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James Sullivan, Alembic Global Advisers - Analyst [38]

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Okay. Great. And if I could just squeeze one more in here. Do you guys have any color or any updates on your assessment of the demand for the end markets for exported LPGs out of markets? What are the conversations like from those guys in terms of looking for markets [lower] volumes?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [39]

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James, if I heard your question right, how is the outlook on LPG markets? It's strong. It's booming. And so we'll be able to -- we have capacity that we can use on Mariner. It's penciled in as propane, but it is both propane and butane, technically, and it can be a mix and it can be made at the right combinations to serve the different LPG markets in the Atlantic basin. So that is really emerging as another demand source out of Marcus Hook. So we think it has a bright outlook.

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James Sullivan, Alembic Global Advisers - Analyst [40]

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Great. Thank you guys. Appreciate it.

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Operator [41]

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Our next question is from Brian Singer with Goldman Sachs.

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Brian Singer, Goldman Sachs - Analyst [42]

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Thank you. Good morning.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [43]

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Hi, Brian.

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Brian Singer, Goldman Sachs - Analyst [44]

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My first question is a follow-up with regards to one of the earlier questions here. When we think about the productivity gains and the potential for cost inflation, the new pipelines and associate tariffs coming on, how do you think about your operating costs per Mcfe the over the next couple years, less so in 2017, but more, what's that trajectory, given the visibility of production and some of these tariffs?

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Glen Warren, Antero Resources Corporation - President and CFO [45]

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Yes, you know, we've already got in service quite a bit of our FT portfolio. So we don't expect a large increase in the flow-through from FT to operating cost. But it goes up by a few pennies over the next few years. So not significant.

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Brian Singer, Goldman Sachs - Analyst [46]

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Got it. Okay. Thanks. And then on the completion front, you continue to highlight the increases in proppant loading, can you talk more about your expectations for EURs for the 2,500 pounds per foot laterals, the relationship that you see between proppant load and EUR and where, if at all, do you see constraints proppant loading wise?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [47]

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Yes, that's a good question, Brian. And that is why we're running the pilots. We're not sure where the breakover point, the point of diminishing returns will be. We're very early in the 2,500 pound. The expectation, of course, would be that it's better than the 2,000 pound. But we don't know yet. So expect to have good results, but we shall see. And even, we'll have to see initial rates and then watch the curves over time. We're pretty conservative. And we'll be watching to see if it's worth the extra effort. We think it'll work. We think it will be good. And that's why we want to do it early, while we still have 3,000 to 4,000 more locations to drill, just to figure it out on the early end. But it is early.

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Brian Singer, Goldman Sachs - Analyst [48]

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Thanks. And you may have said this already, but what's the incremental cost for the 2,500 versus the 2,000?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [49]

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Not much. Less than 10%, per stage.

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Brian Singer, Goldman Sachs - Analyst [50]

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Got it. Thank you.

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Glen Warren, Antero Resources Corporation - President and CFO [51]

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Yes. Thanks, Brian.

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Operator [52]

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And our next question is a follow-up from David Deckelbaum with KeyBanc.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [53]

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Hey, David.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [54]

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Thanks, guys. Sorry to hop back in here with one more, but I did want to just ask about how, at least in the press release, you guys discussed that a portion of your wells in the Utica are going to be on existing pads this year. I wanted to ask the, in pointing that out in the press release, is that more of an indication that your cycle times in Utica should be relatively compressed this year, or is this a new strategy to test reentering existing pads across Appalachia and leverage some of the costs that you've already sunk in there?

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Paul Rady, Antero Resources Corporation - Chairman and CEO [55]

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Well, I think it -- well, maybe it signals both. But it especially just reflects the fact that these are big pads and typically when we get on a pad, we'll have 4 or 5 wells going in one direction in a pitchfork pattern. And we'll move off it just because of that cycle time, that it can take 180 days or more to drill and to complete. And so the sales delay is a little bit of an effect there. So we come in, we build the pad, we drill them all in one direction, frack them out, put them online and then come back at a later date, maybe a year later, and get on the same pad and drill in the other direction. And so it's just a way to reduce the cycle time. And so I do think it will reflect that we'll have shorter cycle times in the future when we go back to existing pads, that it's a much more quick in and out and the infrastructure is there. We do have plenty of pads where we just drill the pitchfork in one direction and can come back and drill in the other direction. And so we've been saving these. And these definitely fit into our drilling schedule.

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Glen Warren, Antero Resources Corporation - President and CFO [56]

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And to follow up to that, David, when you're drilling $10 million to $15 million NPV wells, then that doesn't really move the needle a whole lot, it's really more about where you have infrastructure and what are the best locations to drill.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [57]

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Got it. So this is more a coincident of the Utica program, which I guess will start showing up in the Marcellus program over time.

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Paul Rady, Antero Resources Corporation - Chairman and CEO [58]

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It's true. And one more add-on there to what Glen just said, our typical compressor stations might be $120 million to $160 million a day, and you can see when you bring on big pads, you max out the compression just with the pitchfork in one direction. So part of the coming in and then moving off the pad halfway through it is to fit the infrastructure.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [59]

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Thanks for taking the follow-up, guys.

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Glen Warren, Antero Resources Corporation - President and CFO [60]

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Thank you.

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Operator [61]

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This concludes our question-and-answer session. I would like to turn the conference back over to Michael Kennedy for any closing remarks.

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Michael Kennedy, Antero Resources Corporation - VP of Finance and Head of IR [62]

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Thank you for participating in today's conference call. If you have any further questions, please feel free to contact us. Thanks again.

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Operator [63]

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