Good afternoon, everyone, and welcome to the Antero Midstream Partners LP First Quarter 2018 Earnings Conference Call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star and then one. To withdraw your questions, you may press star and two. Please also note today's event is being recorded. At this time, I'd like to turn the conference call over to Mr. Michael Kennedy, Senior Vice President of Finance and Chief Financial Officer of Antero Midstream. Sir, please go ahead.
Thank you for joining us for Antero Midstream's first quarter 2018 investor conference call. We'll spend a few minutes going through the financial and operating highlights. Then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteromidstream.com or www.anteromidstreamgp.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 management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero Resources, Antero Midstream, and AMGP, 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.
Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Before I turn over the call to Paul, I also quickly want to provide a brief update on the special committees that were assembled after soliciting feedback from AR's largest shareholders. As previously announced, AR formed a special committee consisting of independent directors to evaluate the merits of potential measures to enhance Antero's valuation. In conjunction with this review, AM and AMGP have also established special committees. I'd like to point out that the independent directors on the three special committees are not directors associated with private equity. All three special committees have hired financial and legal advisors and are working diligently to evaluate a range of potential measures.
There is no definitive timetable for completion of this evaluation. There can be no assurances that any initiatives will be announced or completed in the future. As I hope you can understand, because of the nature of this process, we will not be able to address any questions related to it or discuss it further during today's call. Joining me on the call today are Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream, and Glen Warren, President and CFO of Antero Resources and President of Antero Midstream. I'll now turn the call over to Paul.
Thanks, Mike. Thank you to everyone for listening in to the call today. I'll begin my comments today with a discussion on the operational improvements at AR. Mike will then walk through first quarter 2018 results and the five-year outlook at AM. First and foremost, both AR and AM had exceptional quarters on the operational front. Despite difficult operating conditions due to snow and ice in the Northeast, processing outages, and pipeline downtime, AR was able to deliver record net production of 2.38 Bcf a day. Production for the quarter represented an 11% increase over the prior year period and came in ahead of expectations.
In addition to delivering on production, AR built on its momentum from 2017 with respect to drilling and completion efficiencies, including some company operational records, which I'll highlight on slide number three, titled "First Quarter 2018 Drilling and Completion Execution." Starting on the top left portion of the slide, in the Marcellus, we improved our average drilling days to 11.5 days from spud to TD, which represents a 4% reduction from 2017 average levels. Completion stages per day in the Marcellus averaged 4.3 stages per day for the full quarter, but increased to a company record of 5.1 stages per day in the month of March as the inclement winter weather subsided.
This is particularly impressive given that we increased proppant per foot in the Marcellus by 23% to over 2,000 pounds per foot and increased lateral lengths by 8% as compared to year-ago levels. In addition, during the quarter, Antero completed its longest lateral to date in the Marcellus at nearly 14,400 feet sideways and four Utica wells averaging 17,400 feet sideways in length. From an AM capital efficiency standpoint, these longer laterals, along with more wells per pad, result in AM capital efficiency through shorter pipeline mileages. In addition to the operational highlights at AR, I wanted to briefly touch on a few financial highlights. During the first quarter, AR generated strong cash flow growth, as shown on slide number four, titled Cash Flow Growth Deleveraging Profile.
Cash flow generation resulted in a reduction in AR's standalone leverage to 2.5 times as of March 31st, which is an all-time low. In our view, the strength and stability of our sponsor directly supports the growth and success of our MLP. Additionally, the first quarter represented the 15th consecutive quarter in which AR's all-in natural gas price realizations exceeded NYMEX Henry Hub prices. For reference, since AR's IPO in 2013, AR has realized all-in natural gas prices above $3.50 per Mcf in all 19 quarters, excluding the impact of WGL, that's Washington Gas and Light, in the third quarter of 2017. This consistency is a direct result of our long-term transportation and hedging strategy, our focus on execution, and our ability to deliver consistent results despite the volatility in both NYMEX gas prices and Northeast differentials over the last several years.
Before Mike goes into the details, I wanted to reiterate how excited we are about our five-year plan. We are pleased with the momentum that both AR and AM have generated during the first quarter, since announcing our long-term plan at our inaugural Analyst Day in January. The scale, production growth, and financial stability of AR, combined with AM's ability to efficiently build out midstream infrastructure gives us confidence in our long-term plan and outlook. With that, I'll turn the call over to Mike.
Thank you, Paul. I'll first touch on the distributions for AM and AMGP for the first quarter. We recently announced an AM distribution of $0.39 per unit, a 30% increase year-over-year, and 7% increase sequentially. Additionally, AMGP announced a distribution of $0.108 per share, or a 44% increase sequentially. The first quarter distribution at AM was the 13th consecutive distribution increase since its IPO, and the AMGP distribution was the third consecutive distribution increase since its IPO. Turning to page five, titled "Delivering on November 2014 AM IPO Promise," I wanted to touch on our track record of delivering on our distribution and coverage targets. We are extremely proud that we have delivered on all of our distribution growth targets since our 2014 IPO, including through the commodity downturn.
In fact, in addition to delivering on our distribution targets, we have exceeded our DCF coverage targets by 22%. This outperformance is driven by our just-in-time capital investment philosophy, disciplined financial policy, and integrated plan with Antero Resources. Now let's move on to first quarter results, beginning with slide number six, titled "High Growth Year-Over-Year Midstream Throughput." Starting in the top left portion of the page, low-pressure gathering volumes were a record 1.8 Bcf per day in the first quarter, which represents an 11% increase from the prior year quarter. Compression volumes during the quarter averaged a record 1.4 Bcf per day, a 37% increase compared to the prior year quarter. The growth in compression volumes was driven by AM adding two new compressor stations, or 440 million per day of incremental compression capacity during the quarter.
High-pressure gathering volumes were 1.8 Bcf per day, a 12% increase over the prior year. High-pressure volumes were 95% of low-pressure volumes, which is the typical relationship. Joint venture gross processing volumes were 519 million per day during the first quarter. As previously mentioned, the AM MPLX joint venture placed Sherwood 9 online in early January, which brings the joint venture's total processing capacity up to 600 million per day. By year-end 2018, the joint venture expects to have 1 Bcf per day of processing capacity, which illustrates the significant growth and success we have achieved with the joint venture in just the first two years. Moving on to the water business. Freshwater delivery volumes averaged a record 221,000 barrels per day, a 50% increase over the prior year quarter, driven by increased completion activity by Antero Resources.
Specifically, AM was able to service two 12-well pads simultaneously during the quarter, requiring over 11 million barrels of water with its freshwater delivery system. The record volumes are more impressive due to the fact that we overcame inclement weather during the quarter, as Paul indicated earlier. Without AM's integrated water system, AR would not have been able to maintain its completion schedule with trucked water volumes. To put it into perspective, the 11 million barrels on just those two pads alone would have required over 120,000 truck trips. This is another example of the benefits of the integrated water system and operations, which allows AR to execute on its long-term development plan. Moving on to financial results. Adjusted EBITDA for the first quarter was $161 million, a 35% increase compared to the prior year quarter.
The increase in adjusted EBITDA was primarily driven by increased throughput in freshwater delivery volumes. Equity distributions from Stonewall and the processing and fractionation joint venture totaled $7 million during the first quarter. Distributable cash flow for the first quarter was $130 million, resulting in a healthy DCF coverage ratio of approximately 1.3 times. Adjusted EBITDA and DCF did not include any contribution from the Antero Clearwater Facility. During the first quarter, we successfully ran volumes through the plant throughout the quarter, including a temporary period running at over 40,000 barrels per day. However, we decided to extend the commissioning phase of the plant and fine-tune operations in order to ensure that we will efficiently and safely operate the plant over the long term. As a result, AM continues to capitalize the facility for accounting purposes. We expect to place Clearwater into full commercial service during the second quarter.
During the first quarter, Antero Midstream invested $94 million in gathering infrastructure and $34 million in water handling infrastructure, including $19 million for the construction of the Antero Clearwater Facility. In addition to gathering and water, AM invested $17 million in the processing and fractionation joint venture during the first quarter. Moving on to the balance sheet and liquidity, as of March 31st, 2018, Antero Midstream had $660 million drawn on its $1.5 billion revolving credit facility with $9 million in cash, resulting in $850 million in liquidity and a net debt to LTM EBITDA ratio of 2.3 times. I'll finish my comments on slide eight, titled "AM is at an inflection point," with a summary of the strides we have made both at AR and AM toward executing our five-year plan.
Our strategy has always been to efficiently invest capital, supporting a strong and growing sponsor, which, as Paul mentioned, is only getting stronger. We will continue to leverage our visibility into AR's development plan to generate attractive project and corporate-level rates of return. We are pleased with the financial and operational execution in the first quarter of our five-year plan and are excited about the future. With that, operator, we are ready to take questions.
Ladies and gentlemen, at this time, we'll begin the question and answer session. To ask a question, please press star and then one. If you are using a speakerphone, we do ask that you please pick up your handset before pressing the keys to ensure the best sound quality. To withdraw your question, you may press star and two. Once again, that is star and then one to ask a question. We'll pause momentarily to assemble the roster. Our first question today comes from Jeremy Tonet from JPMorgan. Please go ahead with your question.
Good morning.
Morning, Jeremy.
Thanks. I wanted to start off with the frac volumes at the JV. It looks like it came down a little bit quarter-over-quarter here, was just wondering if that was related to Mariner East outage and if you could provide any color on how you think those volumes will trend next quarter and just kind of thoughts on NGL takeaway from the basin.
Yeah. Processing, as you know, for Antero volumes, is all at Sherwood, which was up. The fractionation volumes, however, have third-party volumes, and those were down quarter-over-quarter. That was really due to the weather and pipeline disruptions and not as much ME1 during the quarter. The Hopedale frac number 3 was down due to the third-party volumes.
Got you. Do you expect resolution to that? Should we see a bounce back this quarter or?
Yes, you should.
Okay, great. Thanks for that. Just wanted to see with regards to the fresh water, if you could provide a little bit more color there. I think 1Q was a bit stronger of an uptick than we were thinking, not as much over the fourth quarter. Is it just kind of timing there or any other color that you can provide as far as how you see that ramp goes up across the year versus your guide?
Yeah, it is timing. It should be down going forward approximately 10%-15%. You can really kind of see that in the fresh water wells that were serviced during the quarter. We serviced 46 wells. Our guidance for those fresh water was 150-160. Just looking at that and maintaining that guidance, it should be about 35 wells per quarter going forward. That's down about 10%-15%.
Great. Thanks. One last one. I think you noted a high pressure, low pressure relationship being about 95%, and that's typical. I'm just wondering, is that a typical level kind of across the forecast period or how should we think about that?
That was really a comment made because when we had some issues with Washington Gas Light Company and had to move gas up towards Dominion South, we use a high-pressure line for Antero Midstream called the Bobcat Connector. We had more high-pressure volumes than low pressure in the third and fourth quarter of 2017. That is not typical. The typical relationship is 95%, and that returned in the first quarter as everything was flowing as planned.
Great. One last one, I'm pretty sure you won't be able to answer, but maybe try anyways. As far as the committees, is there any timeline as when there might be a resolution? A certain period when it would be done and we might expect to hear something there?
No, there really isn't. We've said a matter of months in terms of resolution rather than quarters, but there's no particular drop-dead date on that. It's underway. They're working diligently. There's progress being made. That's about all we can say at this point.
That's all for me. Thanks for taking my question.
Thanks, Jeremy.
Our next question comes from Matthew Phillips from Guggenheim. Please go ahead with your question.
Thanks, guys. A follow-up NGL question here. This was discussed briefly on the AR call, but could y'all elaborate on the IRRs as you see it for dry versus rich development and the decision process over the remainder of this year into next year for capital allocation on dry versus wet wells?
Yeah, I think it's safe to say that we usually see a multiple in terms of the rates of return that we see on the rich gas wells versus dry gas wells today. I think some of our best dry gas wells are really going to be the Ohio Utica dry gas wells, the ones that we just brought on in December. Even then, those don't compete head-to-head with the rich gas returns that we see, particularly 1,250 to 1,300 BTU is kind of our main corridor these days, and that's where we see two and sometimes even three times the returns in the rich gas area that we see in the dry gas. That's on a half-cycle basis. Similar relationship holds maybe even more so on a full-cycle basis.
Got it. Even if we were to see NGL prices come off a bit here, it wouldn't necessarily impact the decision to switch primarily over to dry, it sounds like. There's a pretty big cushion there?
Yeah, that's correct. We'd stick with the rich.
Got it. That's all for me. Thank you.
Thank you. Thanks, Matthew.
Our next question comes from J.R. Weston from Raymond James. Please go ahead with your question.
Hey, good morning.
Hi.
I just wanted to ask about Clearwater for the rest of the year. Sounds like commissioning was fine-tuned a little bit in the first quarter. Just wondering if there's any color on the ramp-up, I guess if you want to call it that, in the second quarter, for the balance of the year, and just any updated thoughts on the possibility for third-party business given the excess capacity.
We expect that to come on in the second quarter, and when we deem it to be in operation, it should be around that 40,000 barrels of water per foot. That's actually ahead of our initial projections a couple of years back when we thought it would come online with 30,000 barrels of water. That's because the advanced completions that we're using are using more water, we have more produced in flowback water. 40,000 barrels a day of water throughout the year, starting sometime mid-second quarter-ish.
In terms of third-party volumes, the plant can ultimately process 60,000 barrels a day. There's a delta of 20. The time period is not that long before we fill it with all Antero volumes. We do have the potential to take third-party volumes in the meantime, which would be maybe over the next six or eight months. The cost that third parties compete with is their alternative is to haul the water to Eastern Ohio for injection in general, and that's more expensive. We're optimistic that we'll be able to fill the void for that interim period with third-party volumes.
Thanks for that helpful color. I guess maybe switching gears a little bit, just wonder if there are any updated thoughts on the outlook at AR just based on the obstacles that Rover and Mariner East have faced over the last several months. Just wondering if there's any change at AR and what that can mean on the midstream side, and maybe if you could talk about some of the takeaway capacity alternatives that you have if those projects are further delayed.
We're very close with Rover. Rover phase 1 has already made it to Clarington and to Sherwood, it has made it to the Utica, and it's in the final throes the next month or two of making that to Sherwood. In the meantime, we do have enough capacity before Rover comes to Sherwood to move our gas. We have enough FT to take it to other markets. The alternatives, generally it would be to TETCO, Dominion, and then some going to the Gulf through Tennessee. Should be good. We do have those good alternatives on the gas side. We are looking forward to Mariner East 2 on the liquid side, of course, and the estimates are second quarter to maybe risked third quarter. We'd like to see that.
I think Glen spoke in the last conference call that there could be a hit to cash flow if it's delayed through the end of the third quarter, cash flow to AR of roughly $30 million. We'd rather have it than not during the summer. It's the winter where the Northeast region can absorb a lot of the liquids. There are good local markets, but once you get into the third quarter, you do have to rail to Conway, and you do see a price decrease, and that's what hits the EBITDA cash flow.
That $30 million was for a delay to year-end, we certainly don't anticipate that. If it were delayed six months towards year-end, AR could see a hit somewhere in the $30 million range just because we would have to rail that product rather than ship it by pipeline.
Appreciate all the color. Thank you.
Yeah. Thanks, J.R.
Our next question comes from Vikram Bagri from Citi. Please go ahead with your question.
Good morning, guys. The first question I have is, AM and AMGP entered into these amended and restated indemnification agreements with the executives recently. Can you talk about what the major changes were, if that is related to the special committees? Maybe I'm reading too much into it, but does that mean special committees are making progress sooner than expected?
Yeah, I would say that those were just cleanup items as the outside counsel on the special committees looked at the indemnity agreements to make sure that there's plenty of protection for independent board members and all that. That often happens when you have a different set of legal eyes looking at documents. I would just phrase that as or put in a box of just cleanup work. I wouldn't read anything into that relative to progress or anything material, no.
Great. Switching gears. The second question I have is about maintenance CapEx. The D&C maintenance CapEx at AR is somewhere around $500 million. How should we think about number of maintenance well-
Vikram, you cut out. I don't know if you're still on the line, but if so, could you repeat that last part of the question?
You cut out just at the, "How should we think about maintenance CapEx?
Yeah. I guess I'll anticipate his question, but it generally runs about 10% to 12% of EBITDA for Antero Midstream going out. That same $500 million you referenced for AR for the five years, if you put kind of 10% to 12% of EBITDA, that's generally in the range where it comes out at.
Once again, if you would like to ask a question, please press star and then one. To withdraw your questions, you may press star and two. Our next question comes from Ethan Bellamy from Baird. Please go ahead with your question.
Gentlemen, any further thoughts on third-party midstream service opportunities and separately potential M&A at the midstream level?
Third party, I think it really falls, Ethan, into the water category, whether it's fresh water or wastewater treatment. I think those are the most near-term third-party opportunities for us. As far as M&A at the midstream, the organic growth story is so prevalent here. I'd say it's not highly likely, but we do keep our eye on assets in Appalachia, there's always that potential.
Okay. Thanks, Glen.
Thank you.
Thanks, Ethan.
Our next question comes from Holly Stewart from Scotia Howard Weil. Please go ahead with your question.
Good morning, gentlemen.
Hi, Holly.
Maybe just a quick focus on ME2. I guess I apologize if I missed this earlier on, what has been causing the delay to get that project in service?
What has been causing the delay, Holly, is the difficulty as they get down on the east end of the line. They're into the suburbs of Philadelphia as they get towards Marcus Hook. Because there is culture there, the preferable way to do the stream crossings and other crossings is to bore it, so horizontal directional drilling to go underground rather than open trench. The more straightforward way in a lot of cases is to do open trench crossings, but in an area with a lot of population, it's harder to do that. I'll put my geologic slant on it, that over in that Philadelphia area, the bedrock that they have to drill into is metamorphic rock.
It's schist, and so it's highly fractured.
As you're drilling a horizontal directional boring, you use drilling mud in order to clean out the cuttings, and it all comes back to the surface in a well-behaved system. If you have fractures down there, the mud starts seeping away, and it can come up anywhere along the fracture, and that's what they call inadvertent return. I don't know where it comes up. They monitor and sounds as though the quantity is quite small But still, they're very sensitive there. The drilling mud is natural ingredients. Usually, it's barite, which is a clay, which is just mined out of the earth, but it stops the leakage or the going into fractures. When it's highly fractured, it's hard to control that. They've had these inadvertent returns.
With an abundance of caution, they get shut down until they can develop a new plan, and there's a waiting period. Each time they get shut down, there's a time period, it might be 30 days, to appraise the situation, consider the solution, and then go forward again. They're in the final throes, but it's not easy for them, so we understand.
Okay, we're still on a waiting period, I guess, on moving forward.
Right. Yeah. Optimistically, the end of this quarter, and risk then sometime in the third quarter.
Okay. I think you've referenced in the past a potential investment in that project. Is that something that you're still considering post in-service? Is there a timeline that you would have to make a decision on that? I guess, how should we think about that?
Yeah. As we've said in the past, Holly, that's one of the ones downstream that we have had our eye on. I think there's still potential for that. Time will tell.
Okay.
We'd like to see it get completed. Maybe something happens there. We'll see.
Okay. That's great. Thanks, guys.
Yeah, thanks, Holly.
Our next question is a follow-up from Jeremy Tonet, from JPMorgan.
Hi. Thanks for taking one last one.
Sure.
For modeling purposes, thinking forward as far as AR production growth goes, how should we think about what volume goes towards the JV processing side versus maybe legacy MPLX processing units? Is there any guides that you can provide there?
All incremental growth goes to our JV.
Got you. That's it for me. Thank you.
Thank you.
Thanks, Jeremy.
At this time, in showing no additional questions, I'd like to turn the conference call back over to management for any closing remarks.
Thank you for joining us for our call today. If you have any further questions, please feel free to contact us. Thanks again.
Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending. You may now disconnect your lines.