Michael N. Kennedy - Antero Resources Corp. Paul M. Rady - Antero Resources Corp. Glen C. Warren, Jr. - Antero Resources Corp..

Subash Chandra - Guggenheim Securities LLC Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Drew E. Venker - Morgan Stanley & Co. LLC Holly Barrett Stewart - Scotia Howard Weil James Sullivan - Alembic Global Advisors LLC Kevin Moreland Maccurdy - Heikkinen Energy Advisors LLC Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

Jeffrey Robertson - Barclays Capital, Inc..

Good morning, and welcome to the Antero Resources Third Quarter 2017 Earnings Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded.

I would now like to turn the conference over to Michael Kennedy, Senior Vice President of Finance. Thank you..

Thank you for joining us for Antero's third quarter 2017 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.

Additionally, we have revised our corporate website presentation, which is separate from our earnings call presentation and can be found on the Antero Resources' website. Before we start our comments, I'd 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..

Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to provide an operational update with the focus on our long lateral drilling, and our continued productivity gains.

I'll then describe our significant exposure to the rising liquids pricing environment and finish with a discussion on how this impacts our long-term capital budget and development plans.

Glen will then highlight our third quarter financial results, provide an update on our new credit facility agreement, and touch on the recent delevering program that we completed in September.

He will then round out his commentary with a discussion on Antero's long-term financial outlook, as we transition from a company that has – has historically outspent cash flow to one that expects to generate free cash flow in the coming years.

I'll begin my discussion with the continued productivity gains we are seeing from our higher intensity completions. On slide number two titled higher intensity completions, our increasing EURs, we have provided an updated chart, showing the impact we are seeing from the various proppant intensity levels in the Marcellus.

The black dashed line represents a 2.0 bcf per thousand wellhead EUR type curve and the green line demonstrates that aggregate production from our 1500-pound per foot advance completions dating back to early 2016 support that type curve.

The red and blue lines represent the average cumulative wellhead production per well for 1,875 pound and 2,500 pound per foot completions. As you recall, we showed this same slide during the second quarter earnings call and the 2,500 pound per foot completions were still in the very early innings of production.

As you can see from the update, the 2,500 pounds per foot completions continue to significantly outperform the 2.0 Bcf per 1,000 wellhead type curve by an average of 17% with over 240 days of production.

While it is still early, as it relates to assigning a new type curve to 2,500 pound per foot completions, we remain positive about the benefits of the increased proppant intensity.

The continued productivity gains are one of the major factors that have enabled us to remove significant capital from our long-term budget plans, while still delivering the same attractive production growth. The second operational factor I'd like to highlight is our continued industry leadership in drilling long laterals.

Directing you to slide number three titled longer laterals materially improve economics, the histogram on the middle of the page illustrates Antero's drilling program by lateral lengths. The green bars represent the wells drilled to-date.

The red bars represent the 2017 program and the orange bars represent our 2018 to 2020 planned laterals on our existing acreage position.

As shown by the green bars, Antero has been a leader in drilling longer laterals with nearly 900 wells drilled at an average lateral length of 8,250 feet, and 230 of those were drilled with a lateral length longer than 10,000 feet.

If you look at the red bars and orange bars, you will see how the distribution of wells shifts further to the right, as we have focused much of our 2017 to 2020 drilling program on lateral lengths in the 9,000 foot to 15,000 foot plus range.

Longer laterals at 9,000 plus feet generate materially higher well economics, as you can see at the bottom of slide number three. As many of you know, Antero has done an extensive technical analysis on acreage configurations, well results, and the geology underlying our competitors in the core of the Marcellus and the Utica.

Based on extensive analysis, Antero holds over 30% of the long lateral inventory beyond 10,000 feet, outpacing our closest peer by wide margin. In fact, 24% of our undrilled well inventory is made up of laterals longer than 10,000 feet.

So not only do we have the quantity of locations, but we also have the quality in core locations that have the contiguous acreage to support a long lateral drilling program.

The ability to continue pushing the average lateral length of our locations has been a key factor in the capital savings we have achieved to-date and expect to achieve over the next several years. Turning to slide number four titled improving capital efficiencies.

If you compare the long-term plans we have in place around this time last year, which is represented by the yellow bars on this slide, with our current outlook, which is shown in the orange bars, we've been able to remove 200 wells from our development plan through 2020.

We expect this to result in nearly $1.5 billion of capital savings from our budgets over the same time period, while delivering nearly the same production growth over that time.

This is a true testament to the operational gains we've made to-date from increased efficiency and productivity, and a focus on longer lateral development and right sizing the DUC backlog.

As outlined in the table at the bottom of the page, these improvements translate into flat, D&C capital spending in 2018 at $1.3 billion and a small increase in 2019 and 2020 levels to only $1.5 billion each year.

We're excited about this progress and expect it will play a major role in our efforts to spend within cash flow and deliver substantial value to shareholders. Shifting gears a bit. I want to spend a few minutes discussing the recent run up in natural gas liquids prices and what that means for our business and long-term plans.

Directing you to slide number five titled largest NGL producer in the U.S., we are – Antero is currently the largest producer of NGLs in the U.S. with one 105,000 barrels a day of NGL production during the quarter. On top of that, we also have the highest NGL revenue exposure as a percent of our pre-hedged total product revenues at 34%.

As you know, we built our business over the years with a strong focus on the liquids-rich areas of Appalachia, and we are now very well positioned to capitalize on the rising liquids price environment. This is a key differentiator for Antero relative to our peers.

To provide you with more color on this, I'll point you to slide number six entitled significant increase in C3+ NGL netbacks. Since 2015, Antero's realized C3+ NGL price has increased 70%. And looking ahead, based on strip pricing, we expect this to continue for the years ahead.

In fact, as outlined on slide seven titled powerful C3+ pricing upside exposure, we expect 2018 cash flow from our C3+ NGL production to increase by nearly $390 million from 2017 levels.

Glen will provide more details in a moment, but the combination of the operational gains and improvement in NGL pricing has resulted in our ability to fund our expected drilling and completion capital needs with cash flow from operations, providing us with the ability to return capital to shareholders in the coming years.

With that, I'll turn it over to Glen for his comments..

Thank you, Paul. In my comments today, I will highlight our third quarter financial results, provide an update on our new credit facility, and expand on the completion of the recent delevering program. I'll conclude with a discussion on Antero's transition from an outspend model to a free cash flow model.

Let's first discuss some of the key highlights from the quarter. Production averaged a record 2.3 Bcfe per day for the quarter, including a record 112,000 barrels a day of liquids.

The liquids production during the quarter consisted of 6,900 barrels a day of oil and over 105,000 barrels a day of NGLs, representing a 38% increase from the prior-year quarter and a 9% increase sequentially.

Moving on to financial highlights from the quarter, we generated $336 million of consolidated EBITDAX, excluding the impact from the recent $750 million hedge monetization, which I'll touch on in a moment. This represents a 3% increase from the prior-year quarter, resulting in a consolidated EBITDAX margin of $1.58 per Mcfe.

We realized $2.71 per Mcf before hedges on our gas production during the quarter, representing a 5% decrease compared to the prior-year quarter and a 14% decrease sequentially.

The decrease in realized gas pricing for the quarter was driven by two separate contract disputes with Washington Gas Light Company and affiliates, which we'll refer to as WGL, and South Jersey Resources Group and affiliates, which we'll refer to as South Jersey.

The contract disputes resulted in a combined $0.26 per Mcf negative impact to our realized natural gas prices for the quarter. Without the negative impact of both contract disputes, Antero realized natural gas price before hedges would have been $2.97 per Mcf or a $0.3 differential to the average NYMEX Henry Hub price for the quarter.

And our EBITDAX would have come in at $383 million or $47 million higher, resulting in a consolidated EBITDAX margin of $1.80 per Mcfe.

Looking ahead beyond 2017, we do not expect a material impact to our realized pricing and cash flow from these contract disputes due to the expected start-up of the Cove Point LNG export terminal in the first quarter of 2018, additional takeaway capacity expected to be placed in service throughout 2018, and the narrowing of regional basis differentials based on current strip pricing.

We are confident in our position for both cases and will continue to seek damages and resolution in both disputes.

As it relates to liquids, we had an excellent quarter with a realized un-hedged oil price of $42.50 per barrel and a hedged oil price of $45.40 per barrel, which represents a $5.66 and $2.76 differential from NYMEX WTI oil, respectively, for the quarter.

We realized an un-hedged C3+ NGL price of $28.92 per barrel during the quarter, which represents a 65% increase from the prior-year quarter and 60% of NYMEX WTI. Further, liquids revenues for the quarter made up a record 38% of total product revenues with C3+ revenues making up 34% of total product revenues.

The improvement in C3+ NGL realized pricing was driven primarily by the strengthening of Mont Belvieu pricing relative to WTI, driven by an increase in export volumes.

When you combine the improvement in liquids price realizations with the fact that Antero has become the largest NGL producer in the U.S., you really get a sense for the exposure we have to a rising liquids pricing environment, that Paul discussed earlier. We built our business around the liquids-rich areas of Appalachia.

The rising liquids price environment plays a major role in cash flow growth and value creation at Antero. And we plan to continue building on that progress. Transitioning to our funding needs moving forward, I wanted to briefly discuss our new credit facility that we closed on in late October.

We entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion. While we had demand from the existing bank group for over $3.5 billion on a $3 billion ask, we ultimately reduced the ask and commitments to $2.5 billion.

This represented a sizable reduction of $1.5 billion from the previous commitments on our old facility of $4 billion. This reflects the fact that we are essentially undrawn on our facility today and plan to primarily fund our drilling program with cash flow from operations and distributions from our ownership in Antero Midstream.

The new credit facility along with the recent de-levering program position us well to grow production attractively, while spending within cash flow and continue to de-lever the balance sheet. This will ultimately provide us with more optionality over time.

Additionally, there are fall-away covenants in place in the credit facility that will enable us to go unsecured should we receive an investment-grade credit rating. This illustrates the significant confidence placed in our business by the bank group.

Now to expand on the completion of our recent de-levering program as previously announced and shown on slide number eight titled $1 billion de-levering program completed, we successfully monetized over $1 billion of non-E&P assets in September 2017, including the sale of 10 million common units of Antero Midstream and the restructuring of a portion of the commodity hedge portfolio.

As you can see on the bottom chart of the slide, we restructured the hedge swap prices to $3.50 per MMBtu in 2018 and 2019 and $3.25 in 2020. This allowed us to bring forward the value of $750 million in hedge gains, while not changing the overall hedge volume and maintaining some significant commodity price protection.

Specifically, we have approximately 80% of targeted natural gas production hedged through 2020 at $3.43 per MMBtu and future unrealized hedge gains of $1.2 billion through 2023, based on September 30 strip pricing.

It is important to note that the monetization program was also very tax efficient due to the expected utilization of a portion of Antero's $1.6 billion of net operating losses. The program was important for Antero as it effectively reduced our standalone E&P leverage ratio from 3.2 times at June 30 to 2.6 times as of September 30.

The sale of the AM units was an opportunistic event and really highlight the true value held by AR through its ownership in AM, the value that was monetized at a tight discount to the market value and on a tax free basis due to the NOLs I mentioned.

Moving on, I wanted to discuss how the efficiencies Paul described earlier combined with our liquids upside exposure have positioned us to transition from an outspend model to a free cash flow generating model.

Slide number nine entitled capital efficiency drives elimination of outspend shows Antero's consolidated drilling and completion CapEx versus its standalone E&P cash flow, which represents cash flow from operations plus AM distributions.

As you could see on the right hand side of the chart, beginning in 2019, Antero expects to completely fund drilling capital with upstream cash flow, all the while maintaining a 20% production compound annual growth rate from 2017 through 2020.

This speaks to the strides we continue to make on the operational front with our advanced completions and continued operational efficiencies that include drilling longer laterals and reductions in drilling and completion cycle times.

To reiterate a point made earlier, we have successfully eliminated $1.5 billion from our development budget through 2020, while maintaining nearly the same production growth trajectory. This not only results in a significant increase in overall corporate returns, but also generates free cash flow beginning in 2019.

In closing I'll point you to slide number 10 titled attractive long-term outlook where you can see a snapshot of our strategy and long-term outlook from an upstream perspective.

The chart displays the attractive 20% production growth CAGR through the end of the decade that will generate free cash flow, further reduce leverage and ultimately put us in a position to consider returning capital to our shareholders. The completion of the de-levering program is a huge step in our strategy to reduce leverage to the 2 times range.

The strategy is geared towards the long-term vision of continuously developing our 53 Tcfe of 3P reserves at mid-year for many years ahead, which we believe will generate the most value creation to our shareholders. With that, I will now turn the call over to the operator for questions..

Thank you. And our first question comes from Subash Chandra of Guggenheim..

Hi, Subash..

Mr. Chandra, your line is open..

Yeah. Sorry, I was on mute. Hey, Paul. So I guess you have a lengthy discussion of the ongoing litigation et cetera, et cetera.

Is there any sort of imminent timing on those two ongoing issues?.

No, I would say, it's going to unfold over the next year or so, Subash..

Got it.

So, we should see this being continued to be reported in your NGL guidance rather than showing up somewhere as a litigation item?.

Yeah. And it won't be NGL side, it will be the natural gas side of course. But yeah, we'll continue to monitor it and to report it. We do think that....

Okay..

...the conditions will improve over really the very near-term foreseeable future both with narrowing of bases between different indices as well as Cove Point comes on, that shifts deliveries over to Cove Point and mitigate some of the issue with WGL's inability to receive gas at that certain point called Braxton..

Okay.

And I guess what I was getting at was, so if there's a positive resolution, final resolution for you guys, that's going to be a net positive surprise rather than being somewhere on the balance sheet?.

Yeah, that's right, Subash..

Okay. Okay, perfect.

And my second question is on the C3+ proportion of total NGL barrels, how do you see that sort of changing in 2018, if at all from 2017?.

I think it's going to be roughly the same proportion or may be even climbing a little bit on C3+, that if we're recovering roughly 30,000 barrels a day now, we may step it up to as high as 40,000 barrels a day, but the C3+ proportion will grow a little bit above that proportion of 30 out of 150..

Okay. I appreciate it. Thanks..

And Subash, I would point out there is a new slide 13 in the appendix that helps you I think with some of the math on what proportionality we have of propane and butane et cetera within our barrel..

Okay. Got it. Thanks..

And the next question comes from Neal Dingmann of SunTrust..

Good morning, guys. Looking on just at that slide 13 and 34 how positive now, you mentioned with the NGLs just how obviously fantastic those prices continue to be.

I know you've always allocated a large amount of capital that way, but again looking at that high gas or looking at particularly on slide 34 the highly rich gas condensate that strong payback of 1.2 years.

For 2018, will you allocate any more capital towards that region?.

In 2018, we're primarily drilling rich gas locations throughout. So yeah, that's, we're pretty much full allocation towards rich gas in 2018 and over the next several years..

Okay. And then just one last follow up. You were active earlier in the year and last year on acreage acquisitions, I think, now at over 110,000 or 115,000 plus acres.

Will you continue to look at that or now with the inventory life that you have been so large, will that die down a little bit?.

I think it'll die down a little bit, Neal. That our focus is really – certainly, we continue to add around the edges and any tracts (25:48) that we have big tracts (25:49) in the middle of our acreage block. But a lot of what we're doing is now just ticking and tying and getting the last few percent in each of our drill site units.

So we typically – by the time we spud, we're at quite often a 100% working interest. So today, we might be with locations that are on the book at 95% or so, on the books that a lot of that is just the final stages of filling in..

Got it. Lastly if I could just add – sneak one last one on that three-year outlook that you have, what rig plan is that based on? Thank you so much..

It's on a similar this year's rig plans on a 6 to 7 rig program that's the same in 2018. You'll see that capital program is flat, and then it steps up about 2 rigs into 2019. So about an 8 or 9 rig program in 2019 and 2020..

Thanks, Mike. Thanks, guys..

We've got so efficient on our drilling that we're down now to 12 days sort of spud to spud on these 9000-foot laterals. So it just doesn't take that many rigs to deliver that program..

Okay. Great add. Thank you..

And the next question comes from Drew Venker of Morgan Stanley..

Good afternoon, guys..

Hi, Drew..

Good morning, Drew..

Hi.

I wanted to just go back to your prepared remarks talking about potential return of cash to shareholders, and just would like to hear how you guys are thinking about that, the indicators that it's the right time to return cash to shareholders and what method you might go about that if it's buybacks or additional distribution to dividends?.

Yeah. And I don't think I have any direction on that last part.

But I think the real message here is just the way the equation has changed over time, through all these capital efficiencies and the fact that we're actually into the cash flow – free cash flow generation mode here now and that's really just a small handful of companies out there who can grow at these kind of attractive growth rates and deliver free cash flow.

So it really presents a lot of optionality for us going forward.

I think some rough numbers using this $54 oil and $3 gas as you look out over the next number of years, I mean, we expect to be generating somewhere in the $500 million range of free cash flow at AR standalone by the end of the decade and that grows as you go out beyond that sort of looking out towards five years.

And so if you think about the balance sheet, we expect the levers to decline pretty dramatically through that period. So it just presents a lot of optionality using those kind of assumptions. I mean, we see our leverage going down below well under 2 times towards the end of the decade and under 1 times, if you look out five years or so.

So if you think about, say, a 2 times target for your leverage, it just presents a lot of optionality upwards of $3 billion over five years that you could use for a number of things, could be return of capital and that could be dividend program or stock buybacks, it could be consolidation, it could be increased drilling or simply letting the leverage decline towards that 1 times.

So, a lot of options for our board to look at and we're sort of starting that discussion. It's a hot topic around the industry, but the message here is that we're in a position to have those options. So that's pretty exciting for us..

Right. Yeah, that makes sense, Glen. Thanks for all the color..

Thank you..

Just – I have a follow up on that. I think your base plan through 2020 is assuming $54 oil.

So, if we – we happen to have higher oil prices or higher NGL realizations to you than in your base case plan, what do you do with an incremental cash?.

Yeah, we certainly have a lot of leverage to upside in oil prices just going up towards $60 a barrel generates quite a bit more free cash flow. So, same options; it's just you've got more of it, certainly over time.

So that would be exciting for us and we positioned the company strategically for this, of course, being very much focused on liquids-rich and controlling, holding 44% of the future drilling locations in the liquids-rich areas of the Utica and the Marcellus as we count on, we've done a lot of work on that over time just understanding where are the remaining locations and what companies hold them, and we're highly confident in our position.

So, very well positioned for that kind of improvement in liquids prices; so we're hopeful..

Okay.

And if I'm interpreting that right then, it sounds like preference should be either to redirect capital towards those higher liquids cut wells or maybe spend incremental capital instead of just using that free cash flow to pay down debt or was I reading that wrong?.

No, undetermined, I was giving you all the options, return of capital, consolidation, more drilling or simply let the leverage decline. So there are a lot of options to be discussed as we get there. We're not quite there today, but we're getting very close and next year looks terrific.

At those kind of prices assumptions, we're only negative by $100 million or so from a free cash flow standpoint for the whole year, and then by year-end, we're free cash flow positive. So, not quite to that point yet, but just sort of laying out the options for you that we'll be talking about at the board level..

Okay. Thanks..

And the next question comes from Holly Stewart of Scotia Howard Weil..

Good morning, gentlemen..

Hi, Holly..

Good morning..

Just kind of looking at the activity right now, looks like five rigs in the Marcellus with three crews and one in the Utica with one crew, how should we think about the long term I guess three-year outlook that you've provided and how this plan evolves in those two areas?.

Yeah. I think the emphasis is going to be on the Marcellus over the next couple of years anyway, that's the plan that we've laid out. We do have a lot of, 11 dry gas wells ready to come online once Rover comes on in Ohio, and so those are all completed and drilled out and ready to go. So we're just waiting on that Rover 1B Phase to be completed.

But other than that, I think you'll see us focused primarily on the Marcellus over the next few years, Holly, and on the rich gas within the Marcellus..

Okay.

And then since you mentioned the Rover 1B, how should we think about that capacity being filled? You've got the, what, 10 or 11 wells you referenced and those are ready to turn on, would that fill-up immediately and then not with those wells? But just in general would you plan to fill that up pretty quickly and then backfill other capacity or are you just going to fill that over time as the development plan works out?.

Yeah. Holly, it takes on the order of a year to a year-and-a-half to fill Rover. And as you know, 1B will come on by the end of the year, if not sooner, and then Phase 2 comes on, by the end of the first quarter, we'd expect, to Sherwood.

So we'll be filling Rover both with Utica gas, but more importantly with Marcellus gas and so the netbacks to Rover work out pretty well. So that will get preferentially filled relative to some of the other projects that will come on..

Okay, great.

And then final one if I could, just what are the terms of those two contracts with WGL and then South Jersey just thinking about length of contract term?.

Well, South Jersey is the simplest one that I think that runs out in April of 2019. So that one has, whatever that is, 16 months to go, 18 months to go. And that one is the smaller one at 80 million cubic feet a day.

And then the WGL one, there are different tranches that some tranches phase out in the next, well, the first tranche phases out or part of a tranche phases out when Cove Point comes into service by the end of the year. And so then it's a phasing down over the next five years with the remaining tranche being Cove Point, which is a 20-year contract.

So, I think, it's really anywhere from three months to 20 years. I know that's rather broad, but it's a phasing down and their ability to receive the gas also gets phased down or their challenge in receiving it gets phased down over the next year..

Okay. Okay, great. Thanks guys..

The next question will come from James Sullivan of Alembic Global Advisors..

Hey, guys. Good morning, still..

Hey, James..

Just a quick question on slide 4 regarding the average lateral lengths of the plan for the next three years.

I think you show the lengths going down to 9,200 feet from 9,600 in 2019 versus 2018 and then back up to 10,200 feet in 2020 and I'm sure this probably has something to do with DUCs in inventory, but can you just help me out a little bit with that?.

Yeah. And these are estimates at this point in time. We have – we've always had a very active land program and what we find is by the time we get around to actually drilling these pads that the laterals are usually longer than what we lay out in the plan looking out a year or two or three years out.

But part of the message here is just that we've done some of that just over the last year or so and so we have a longer lateral length average in our program over the next few years which drive some of these efficiencies that we've been talking about.

But even more important than that, it's really been just the drilling efficiencies themselves and the frac efficiencies and all that, but the longer laterals certainly will help in the capital program.

And that's an ongoing thing and we're looking into all that again, now, and I think you'll see us come out with even longer laterals on average in this program over the next few years..

So conceptually 2019, by the time we get there, that 9,200 feet will probably be – will be longer. The effort is to drill longer and longer, but this shows what we have in place right now for the land inventory..

Okay. Great. Yeah. I mean, obviously 400 feet between friends doesn't make a huge difference. I think, I'm more thinking about the DUC inventory and you guys mentioned in your prepared remarks about right-sizing that as part of your refining, your longer-term plan.

What do you – because I think there were some legacy wells that maybe were a lot shorter or were drilled long time ago? Can you comment on that? And just maybe how many, how many DUCs you are running in the two basins right now and what you plan to do directionally with them in 2018? Are you working them down or what's the plan?.

Yeah. There are two categories of DUCs of course. I mean the DUCs that we've referred to over the last couple of years were wells that were truly set aside, pads that were set aside for us to come back to later, and part of that which is for controlling capital spending and not completing those wells at the time.

So we have gone back on a number of those, and Mike will be talking about that a little bit in the AM presentation a little bit later. So we've already completed a lot of those. So we don't have many DUCs set aside right now other than the 11 that I mentioned in the Utica, they're just waiting on Rover to come online.

Now as far as just ongoing wells that are in the process of drilling, waiting on completion crews, drilling out, et cetera, we continue to have plenty of those as does everybody that's kind of your working capital, if you will, but we are getting much more efficient with that in reducing our cycle times and not letting pads sort of lay fallow while you're waiting on a completion crew.

So I wouldn't consider us a big DUC holder going forward. So what we'll be completed now over the next year are wells that we've drilled fairly recently and tend to be of the longer lateral ilk, and they tend to be on larger pads where we can zipper frac them and be more efficient on the completions as well. So that's kind of the outlook..

Okay, guys. Thank you. That's very helpful, especially on the set aside – quote, unquote, set aside DUCs. If I could just sneak one more and really quickly here. A little more philosophical here and I'm cognizant that you guys obviously sold down AM this quarter.

And what I'm thinking about here is as you guys thinking further out past into the five years or a decade kind of timeframe, as you move into a more mature phase in terms of the midstream build out.

Can you talk about the rationale for AR to have such a high degree of buy-ins so to speak into AM, and again thinking here more philosophically, strategically rather than are we going to sell 10 million shares here and there?.

Well, it's been a great investment first off for AR, we've got a page in the bigger presentation that shows that it's almost a five timer return for AR in terms of the investment of $1.3 billion back several years ago for the IPO of AM. So it's been a great investment. The outlook is terrific for AM, over the next number of years.

So we like holding that equity and taking the distributions back. So I would say, we don't really have any concrete plans to reduce that that holding of almost 100 million units of AM..

Okay, great. Thank you, guys. I appreciate it..

Thank you..

Thank you..

And the next question comes from Kevin Maccurdy of Heikkinen Energy Advisors..

Hi, Kevin..

Good morning.

Can you – good morning – can you talk about your expectations for Mariner East 2 in-service date and any effects that would have on your production or your pricing?.

Yeah, I think, of course, one wants to look to Sunoco, SXL for all the blow-by-blow detail. But I think industry followers know that they're putting a lot of it in the ground.

Pennsylvania is an unusual state in that there can be more powerful local jurisdictions, I'd say, that can delay things rather than a state-wide green light, so they do get hang up – hung up in county-by-county things that have to work those out. But the original expectation would be November 1.

Now, it's over the course of the winter, and into the spring perhaps. And the impact of that for us, we feel is pretty low, that right now the product prices are high in the Northeast, and we would expect that just as last year, the differentials are pretty narrow during the winter and spring.

And so we don't see much of a suffering of realizations with or with it – without export for the next six or nine months. So we're not saying we're certainly not on the inside on Mariner schedule, but if it is a quarter or two late, that's okay with us, that our realizations and our ability to put our liquids away will be very little impacted..

That's good to know.

And as a follow-up, regarding gas realizations, are you guys still comfortable forecasting a premium to NYMEX for 2018 and beyond?.

Yes, that hasn't changed. And the issue behind the current wide differential in the third quarter and what we expect in the fourth quarter, it's really been a function of where TETCO-M2 is traded and Dominion South relative to other indices.

And I think people as a whole, that analyst investors expect those differentials to narrow quite a bit with all the new pipe coming on including putting Rover and eventually Mountaineer XPress. And also we feel pretty good about that that narrowing, it just won't be as big of an issue going forward. So that kind of goes away.

And then given our overall portfolio, we expect to still be in that 0 to $0.10 premium to NYMYEX going forward over the next several years..

Thanks for the color, guys..

Okay. Thank you..

Thank you..

The next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt & Company..

Good morning. I just....

Hi, Jeoff..

Hi. Just a quick follow up to the Mariner East 2 question.

In the past you guys have mentioned exploring alternatives for that, is that something that you're still actively pursuing and are there any options that standout or has local pricing as you pointed out removed the need to look for those alternatives?.

Yeah. We're pretty focused now on Mariner as really the best option for getting premium prices for export for arbitrage. And so, we feel it's the most viable. So between local offtake in the Northeast as well as Mariner, I think those are our preferred solutions. Others have been floated out there, as you're aware, with reversals and so on.

But although we were supportive, we didn't see the producer community coming in on those and supporting them, so those are probably a little bit longer term. So I think for us NGLs are going to be Mariner, on the ethane side we're looking forward to over to Shell cracker and more ability, more buyers out of Sarnia.

So we think we can stay regional in our NGLs, and between that and Mariner 2 that's where we're focused..

Okay. Thanks for that. And then my next one is just on how the gas takeaway portfolio and I guess growth into that play into the long-term plan.

So you've obviously got excess capacity, you can keep going into, you could also continue to expand that capacity just maybe looking at where the forward curve is today or you could look to maybe moderate either or both of those options, reducing D&C further, potentially leading to more free cash flow generation and sooner.

How do you, I guess, balance and prioritize all those options with what you know today?.

Well, with what we know today, of course, you're right that, we do have some unutilized firm, but because of our growth rate, we see that we're going to fill it fairly rapidly over the next year-and-a-half or so.

We, like other shippers, are going to be buying distressed third-party gas, so the reason that the TETCO-M2 and Dominion South and other distressed indices will trade up, is because those producers will be selling their volume and filling up some of the pipe. So our unutilized, there's a good opportunity to fill with third-party gas.

But it isn't that long over the next several years before we begin to fill our own FT.

What will we do beyond that, as you're probably aware, there's been more of an advent of demand to pull pipes, those being Atlantic Coast Pipeline going to the Southeast and Nexus going to the Northwest, that are putting straws into the constrained area and wanting to buy.

So I think the question is with more of an abundance of pipe coming in, both demand pull and just spare capacity whether we will need to sign on for more FT.

So we definitely have time, we've got the next several years to judge that whether we're going to be signing on to more projects or whether the markets will be there for us to just be able to sell locally beyond what we have in FT right now..

Great. And if I could just sneak one more in. Obviously, a large amount of free cash flow coming towards the end of the decade and you all alluded to even more, which gives you increased flexibility and optionality around what you can do with that.

If we're just trying to think about kind of a base level of spending by the time you get out to 2020, is there a good number to keep in mind in terms of what could hold production profile relatively flat from there?.

I don't have a real specific number there, but I think it's probably in that $700 million range or so, wouldn't you say, Mike?.

Yeah, that's a good number..

All right, thanks for that guys..

Out to 2020 to hold production flat, yeah..

Appreciate it..

And next our question will come from Jeff Robertson of Barclays..

Thanks.

Paul or Glen, can you all just talk a little bit more about what underpins your NGL realization view over the next several years and, in the context of exports, are you all signing any agreements that allow you to deliver NGLs to buyers at a certain percentage of WTI?.

So, I think what underpins I think on the first question, Jeff, is outlook on oil prices, outlook on then C3+ demand, cracking demand. We can see, of course, LPG exports and how those are ramping up to the Atlantic Basin.

So I think our general optimism is tied to those things that there's not only a general lifting with oil prices but a specific lifting as we see more and more cracking customers across the world that need product – need the propane. So that's what underpins things just a little of supply and demand there.

As far as percent of WTI, those products are out there, as you know, both on the physical and the financial side. We haven't done that. And in fact, we haven't done much hedging yet. We've done a little bit as we've seen the price rise. But we're being patient, and so we may lock in. But we'll take advantage of this price rise and let it come to us.

We still see pretty good momentum there. So most likely, instead of doing a percent of WTI, we'd probably just lock the price on swaps for our C3+..

Second question, Paul, as you think about the new or the modified development plan with the 200 fewer wells needed, does that do anything in the context of gathering and processing efficiencies that allow you to realize any benefits at the AR – on the AR cost structure, from having a more maybe a more streamlined build out from Antero midstream, because you just have fewer wells to connect?.

Yeah, you're absolutely right, directionally that's right that longer laterals means fewer pads, which means fewer connections. And so, whether it's taking gas away, low pressure, high pressure, whether it's citing compressor stations. And then really with water delivery, too, that that becomes more efficient with fewer pads and bigger volume per pad.

So that's exactly right..

Okay. Thank you..

Thank you..

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

Thank you, everyone, for participating in our conference 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..