Welcome to the Antero Midstream Fourth Quarter 2016 Earnings Conference Call and Webcast. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Chad Green, Vice President Finance. Please go ahead.

Thank you for joining us for Antero Midstream's fourth quarter and year-end 2016 investor 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 home page of our website at www.anteroMidstream.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 first like to remind you that during this call Antero Midstream management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero Midstream and its sponsor Antero Resources 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 he me on the call today are Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream; Glen Warren, President and CFO of Antero Resources Midstream and President of Antero Midstream; and Mike Kennedy, CFO of Antero Midstream. I will now turn the call over to Paul.

Thanks, Chad. Thank you to everyone for listening in to the call today. In my comments I'm going to highlight the recently announced processing and fractionation joint venture with MPLX slash MarkWest and how it fits in with the significant investment and growth opportunities available for Antero Midstream. Mike will then discuss the strong fourth quarter results and long term outlook through 2020. Beginning with slide number 2 entitled Joint Venture Overview, Antero Midstream signed a fifty-fifty joint venture to develop processing and fractionation assets in the core of the liquids-rich Marcellus and Utica shales with MarkWest Energy Partners, a subsidiary of MPLX. This transaction is very strategic as it aligns the largest core liquids-rich resource base with the largest processing and fractionation footprint in of Appalachia. Looking to the map on the right-hand side of the page, the joint venture will develop up to 11 additional processing plants with 200 million a day of capacity each or a total of 2.2 BCF a day. MarkWest will continue to own and operate Sherwood plants 1 through 6 which are currently running at full capacity. The joint venture processing facilities will begin with Sherwood plant number 7 and go through plant number 10. These are expected to be placed into service beginning actually right now for Sherwood 7, it's being commissioned right now, through the third quarter of Cal 18. The joint venture will have the potential to build an eleventh plant at the Sherwood site and then develop a new processing complex at a to-be-determined location in West Virginia. The new complex will have the potential for an additional six processing plants or 1.2 BCF a day of additional incremental capacity. In addition to processing, the joint venture purchased 20,000 barrels a day of C3 plus NGL fractionation capacity or…

Thanks, Paul. First and foremost, it was another strong quarter for Antero Midstream both operationally and financially. AM announced a fourth quarter distribution of $0.28 per you unit, a 27% increase year over year and a 6% increase sequentially and maintained outstanding DCF coverage of 1.8 times. The distribution marks our eighth consecutive distribution increase since the IPO in November of 2014. AM's 2016 distributions totaled $1.03 per unit, representing 30% year-over-year growth with DCF coverage of 1.8 times. As you can see on slide number 6 titled High Growth Midstream Throughput, the distribution growth and significant excess coverage was supported by an increase in throughput and fresh water delivery volumes. Starting in the top left portion of the page, low pressure gathering volumes were 1.5 BCF per day in the fourth quarter which represents a 35% increase from the prior year and a 6% increase sequentially. Compression volumes during the quarter averaged 920 million per day, a 92% increase compared to the prior-year quarter and an 18% increase sequentially. During the fourth quarter, we placed online a145 million per day compressor station in the Marcellus which brought our overall Marcellus compression capacity to over 1 BCF per day and our combined Marcellus and Utica compression capacity to over 1.1 BCF per day. If you had a chance to listen in to the AR call, we highlighted a recently completed 10 well pad located in the highly rich gas area in West Virginia which was AR's largest producing pad ever, placed to sales with a combined 30-day rate of 200 million per day. From a midstream perspective, the development program visibility allows Antero to bring online significant production and essentially fill compressor stations almost immediately. For example, the compressor station placed online in the fourth quarter was over 85% utilized…

[Operator Instructions]. The first question comes from Brandon Blossman of Tudor, Pickering, Holt & Company.

Good morning, guys.

Good morning.

Let's see. Mike, just real quick, slide 9, what are the equity assumptions there? Our model, I think you can do this all on retained cash flow and balance sheet capacity, but are you assuming any equity issuances to that 2020 target?

We're not assuming any equity issuances. There is the assumption of the completion of the ATM program. The ATM program, I believe, had approximately $180 million left at year-end, so there's the assumption that is completed during that time frame.

Great. Thank you for that. And then big picture question. Strategically you guys have a very attractive cost of capital. You control a lot of the liquids-rich acreage in-basin. Approximately first in line for some pretty attractive opportunities. You've alluded to extending the supply chain here. Would you consider something perhaps as far-fetched as partnering in a pipe or there's a mention of some terminal assets. Is it possible to think of you guys some point in the future as controlling the entire supply chain?

Well, it depends on what you mean by control, I guess, Brandon. All of those are on the table, all those things you mentioned certainly and more of that kind of infrastructure is needed. Some of those announcements have been made recently so all that's on the table in terms of Antero potentially participating either upfront or down the road. So yes, I think that's something that's still within the portfolio mindset.

It will be fun to watch. That's all from me. Thank you.

Thanks, Brandon.

Thank you.

The next question comes from Vikram Bagri of Citi.

Hey, guys. You talked about a 10 well Marcellus pad that you brought online recently. I believe the pad used proppant fluid of about 1750 pounds per lateral foot and the plan is to test as much as 2500 pounds per lateral foot. If I look at some of AR's peers, they have tested even higher proppant loads. I was wondering what does it do to your water requirement per well. Are you assuming 42 barrels per lateral foot in 2017? If that 2500-pound per lateral foot completion technique works, what does it do to your water requirement in 2017?

Our assumption for the 2017 is the Marcellus will have 42 barrels of water per foot and that's based off of that program that we've outlined on that slide. It's a mix of 1,750, 2,000, 2,500 pounds per foot. Obviously if the 2500 pounds per foot turn out to be the most economic wells, there is more water to be used in those 2,500-barrel or 2,500 pounds-per-foot wells. So right now it's kind of based on an average of about 2,000, so if 2,500 is where we trend to in the future, there would be upside to that 42 barrels per foot of water.

It's fairly proportionate. So 2,500 is a 20-ish percent bump in upsizing and so the water would go up by that amount as well.

Okay. And then on fractionation side, I believe the frac is for C3 plus. You talked about some downstream opportunities as well. Is there anything you can do on de-ethanization side given the rejection at the AR level?

Is there anything we can do with DF? Certainly in order to meet pipeline specs, we're doing about 23,000 barrels a day of ethane recovery right now and that's using the 40,000-barrel a day de-ethanizer that's there at Sherwood that is allocated to us. So we can do more de-ethanization and we're just looking for opportunities when we find markets and contracts that put us in the black that pays for DF above gas value, then we DF more. There is another DF on order. So we expect as our overall volumes grow that the first 40,000-barrel a day de-ethanizer will fill up. And so there will be another at least 20,000-barrel a day built at Sherwood over the next couple of years. So as we make these more downstream marketing deals that reward us to extract ethane, to pull it out of the stream, then we'll DF more. We see that happening. Of course the crackers that are proposed, we're a big producer for the shell cracker, 30,000 barrels a day and we may upsize that. And that does reward us above gas value that the pricing contract rewards us to de-ethanize and compensates us to give us a better price than leaving it in the stream. So we expect to see more of that. The new announcement that Mariner East 2 intends to also put the second pipe in the right of way that's Mariner East 2X; that can be used for ethane export. To remind you, we're already an ethane, will be an ethane exporter as soon as ME2 comes on in the fall, to export Borealis. We'll pick it up at Marcus Hook and take it to Sweden to their cracker. But there are probably more of those deals to be had along the same lines that reward us over gas value to extract and export. So we'll definitely be looking at that and looking to capture more value in our ethane. As a reminder, in our more 3P reserves, we have more than a billion barrels of ethane. So we definitely -- it's good to leave it in the stream to get that gas value, the BTU value of the ethane; but even better if we can get incremental value through de-ething and either moving it to domestic or international markets.

Okay. And then just lastly, you obviously maintained a very conservative leverage. I was wondering what the long term target for leverage is and how do you get there?

Yes, the long term target through 2020 is to stay about where we're at right now which is low 2s. Pro forma for this recent equity offering, we're down to 1.9 times. It stays around that level of 2 times. And that's just operating under the assumption that we talked about. No further equity issuances, the completion of the ATM program and then prosecuting on that program of $2.7 billion of organic investment through 2020.

Great. Thank you.

Thanks.

The next question comes from Blaine French of Robert W Baird.

Good morning, guys. It looks like your fourth quarter EBITDA benefited from $7.7 million of distributions from Stone Wall during the quarter. Is this going to be a recurring event every year in the fourth quarter or is this going to be spread out quarter by quarter in the future?

It should be more spread out quarter by quarter in 2017. We had to make a $30 million contribution in the fourth quarter to a Stone Wall project to extinguish all the debt at the project level and that allowed the distributions to occur. So that was kind of a catch-up payment for the months of May through December of 2016. Going forward, that should be on more of a quarterly basis and we will book that as EBITDA when those distributions are declared during the quarter.

Great. And then can you comment on what throughput was for that pipeline during the quarter; and then do you have a rough expectation for what Stone Wall distributions to AM will be in 2017?

It's pretty indicative, that $7.7 million as I talked about, that was for a eight-month period. So it's about a million a month is where we're at; and that's, I think the production forward for 2016 was a bit above $900 million a day was going through that pipeline.

Great. Thank you.

Thank you.

The next question comes from John Edwards of Credit Suisse.

Yes, good morning, guys. Thanks for taking my question. Just to follow up on the last question on Stone Wall. So as far as the distribution there, are you expecting around $7 million, $8 million per year or per quarter, just to be clear?

$1 million per month.

$1 million a month.

Yes.

Okay. Okay. But you're expecting that to be distributed quarterly, not monthly; correct?

Correct, right now, yes.

Okay. And then on your slide deck, I just had a question on your slide 3. Just you've got an arrow there that shows 20,000 barrels a day of ethane going down ATEX. Can you tell us the volumes that are going to the other markets, say Mariner East and also headed to Edmonton, Midwest and Conway?

No. I think local markets are on a steady-state basis about 50,000 barrels a day of propane. But you're actually, John, we're looking at product by product on each of these different markets because it's C5 plus that goes to Edmonton, example and a C3 plus mix that goes to Conway. So why don't you call back in and we can call Mike and we can give you more of the detailed information market by market.

Okay. All right. Fair enough. And then on the $2.7 billion of CapEx through 2020, so that's, it sounds like that's currently known opportunities. I'm just curious if you are anticipating additional opportunities on top of that?

Both. So the $2.7 billion is the identified opportunities that we expect to invest and we do see that there's a good likelihood that there will be other opportunities as well above that.

Okay. Can you share with us any level of magnitude that you're thinking in terms of that?

That could be in the $1 billion range.

Okay.

With additional things that we're looking at, yes.

All right. That's it for me. Thank you so much.

Thanks, John.

The next question is a follow-up from Vikram of Citi.

Just one clarification on JV with MPLX. Is that only on Antero Resource's volumes? In other words if a producer, a third party producer requests an expansion at either Sherwood or at the new facility, will you get an option to participate in that expansion as well? I understand that Antero is the only large producer at Sherwood, but in case another producer ramps up activity can you expand processing beyond your planned 2.2 BCF per day that you outlined?

Yes, so that does cover any third-party volumes that might emerge that come to Sherwood or the new site that's expected to be built in the rich gas area. So it does cover third-party business as well. And the same with the fractionator of course, that is at Hopedale, that's -- includes not only Antero, but third-party volumes.

Thank you.

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

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