Greetings and welcome to the Antero Midstream Second Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. Please note that this conference is being recorded. I will now turn the conference over to our host, Michael Kennedy, Chief Financial Officer. Thank you, sir. You may begin.

Thank you for joining us for Antero Midstream’s second quarter 2020 investor conference call. We’ll spend a few minutes going through the financial and operating 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.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 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 and Antero Midstream 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 press release for important disclosures regarding such measures including reconciliations to the most comparable GAAP financial measures. Joining 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 and President of Antero Midstream; and Dave Cannelongo, Vice President of Liquids Marketing and Transportation. With that, I’ll turn the call over to Paul.

Thanks Mike. I’d like to start by discussing AR's asset sale program which continues to improve AR’s liquidity position and will allow it to repurchase debt at attractive discounts to par. Slide three titled, AR Asset Sale Program Update, details the progress that AR has made to-date on its $750 million to $1 billion asset sale program. During the fourth quarter of 2019, AR commenced its asset sale program with the sale of AM shares to AM for $100 million. Despite the ongoing COVID-19 pandemic, AR was able to execute a $402 million overwriting royalty interest sale in the second quarter of 2020, including $300 million of upfront proceeds and $102 million of contingent payments. In July, AR monetized excess 2021 natural gas hedges for proceeds of $29 million. This brings AR’s total completed asset sales to $531 million. These asset sales have allowed AR to reduce total debt by approximately $365 million, since commencing the asset sale program in the fourth quarter of 2019. In addition, AR is in active discussions for further asset sales and we remain confident that we can achieve the $750 million to $1 billion asset sale target in 2020. We believe this positions AR to repay its 2021 and 2022 maturities and significantly de-risks the Antero complex. Before moving on to AR’s liquidity position, I want to briefly touch on AR’s hedge position pro forma for the recent monetization on slide number four titled, Enhanced Natural Gas Hedge Position. In the second half of 2020, AR is 94% hedged on natural gas production at a price of $2.87 per MMBtu. Due to the overwriting royalty interest sale, AR was previously over-hedged its 2021 natural gas production. As a result, AR monetized a 100 BBtus per day of excess hedges above its 2021 natural gas production for a gain of $29 million. These proceeds were used to continue repurchasing debt at attractive discounts to par. Proforma for the monetization, AR is approximately 100% hedged on its 2021 natural gas production at $2.77 per MMBtu. AR was also active in the second quarter and added 620 BBtus a day to its 2022 natural gas hedge position, which now stands at 1300 BBtus a day. This is consistent hedging and allows AR to maintain a stable development program that benefits AM as well. Slide number five titled, Substantial Liquidity Enhancements at AR, shows the liquidity impact of the asset sale program and significant drilling and completion capital savings achieved to-date. First, as a reminder, AR’s borrowing base under its credit facility was confirmed at $2.85 billion in April, while in excess of lender commitments of $2.64 billion. As of June 30, 2020 AR had approximately $1 billion of liquidity which is depicted on the dark green bar on the left-hand side of the page. Based on today’s strip prices, AR’s development plan is expected to generate $200 million of free cash flow in the second half of 2020, further improving its liquidity position. This ability to generate free cash flow is driven by the significant capital savings and improvement in NGL prices in the second half of 2020, which Dave Cannelongo will discuss in his comments. Assuming execution of the remaining sales at the high end of AR’s targeted asset sale program of $469 million, AR would have $1.7 billion of liquidity at year end 2020 prior to any further bond repurchases. This is more than sufficient to repay both the 2021 and 2022 maturities, which have a total par value of $1.26 billion dollars and market value of $1.04 billion. With that, let me turn it over to Dave Cannelongo, our Vice President of Liquids Marketing, and Transportation.

Thanks, Paul. Let's turn to Slide number six, and begin by discussing the NGL macro environment. The effects of COVID-19 on oil and transportation fuel demand, and the resulting decline in rigging completion crew activity in oil focus shale basins, has set up expectations of a prolonged period of depressed U.S. oil production. More notably, this backdrop results in depressed associated NGL production relative to the volumes that were being produced and fractionated just prior to the onset of COVID-19 around the world. The chart on the left-hand side of the slide illustrates that NGL supply forecasts have declined by over 1 million barrels a day since the beginning of this year. Further, it highlights that it may take several years for U.S. NGL production to return to pre-COVID-19 levels, as the momentum of production declines from the dramatic slowdown in U.S. shale activity over the last four months plays out. The chart on the right-hand side of the slide highlights that sufficient export capacity along the Gulf Coast has helped clear the domestic market and tighten fuel pricing to international pricing. Turning to Slide number seven titled, NGL Price Recovery Expected, we can see that the strength of NGL markets relative to WTI and Brent has continued to stay elevated as a result of more resilient petrochemical and residential commercial markets during this pandemic. Here we illustrate the outperformance of Mont Belvieu propane relative to WTI in 2020. On the right, we see a similar outperformance in propane relative to Brent at the Far East Index or FEI, which is the benchmark in Asia. This is important as Antero has exposure to not only domestic NGL markets but also international destination pricing through our export access on the Mariner East system. While the fundamental backdrop for NGL prices is set up for improved pricing as we head into next year, the limited liquidity in the futures markets for such products does not always reflect the anticipated value further out of the curve. Or put another way, there is typically very little correlation between the future strip in the out years and the ultimate physical price. Slide number eight titled, NGL Pricing Outlook, illustrates the value that some third-party analytical teams, including the Citibank commodities team shown here are placing on NGLs in 2021 and beyond based on their bottoms-up global supply demand models. Looking more closely at the Northeast takeaway capacity, slide number nine titled, Northeast LPG Supply and Demand highlights the reason for a tightening of the Northeast differentials to Mont Belvieu for LPG that has resulted from the Mariner East project. The increase in takeaway capacity out of the Marcus Hook terminal through Mariner East led to markedly improved in-basin pricing relative to Mont Belvieu. Marcus Hook has the capacity to evacuate in excess of 225,000 barrels per day of LPG from the basin through exports, helping support Northeast domestic LPG prices. The anticipated final completion of the Mariner East 2 pipeline system this winter, taking ME 2 capacities to 275,000 barrels a day will create ample capacity to export Northeast NGL production for the next several years. And we anticipate in-basin differentials to remain tight to Mont Belvieu going forward. With that, I will turn it over to Mike.

Thank you, Dave. I'll begin my comments with second quarter operational results, beginning on Slide number 10 titled, Year-over-year Midstream Throughput. Starting in the top left portion of the page, low-pressure gathering volumes were 2.9 Bcf per day in the second quarter, which represents an 8% increase from the prior year quarter. Compression volumes during the quarter averaged 2.7 Bcf per day, a 13% increase compared to the prior year. During the second quarter, AM placed online a new Marcellus compressor station, adding 240 million per day of capacity and supporting the compression volume growth in the quarter. AR's compression capacity was 91% utilized during the second quarter of 2020. Our 50-50 joint venture gross processing volumes averaged 1.4 Bcf per day, a 42% increase compared to the prior year quarter. Processing capacity was 100% utilized during the quarter. JV gross fractionation volumes averaged 33,000 barrels per day, a 22% increase from the prior year. Freshwater delivery volumes averaged 102,000 barrels per day, a 16% decrease from the prior year quarter. The reduction in freshwater delivery volumes is driven by AR moving to one to two completion crews during the quarter as we discussed in our first quarter conference call. AR is currently operating two completion crews on Antero Midstream dedicated acreage. Moving on to financial results, adjusted EBITDA for the second quarter was $201 million, a 2% decrease compared to the prior year quarter. During the quarter, Antero Midstream only received two monthly joint venture distributions compared to three monthly distributions received in prior quarters, resulting in a $7 million reduction in adjusted EBITDA. Distributable cash flow for the second quarter was $152 million, resulting in a DCF coverage ratio of one time. Capital expenditures during the quarter were $59 million, a 63% decrease compared to the second quarter of 2019. During the second quarter, we generated a company record $108 million of free cash flow before return of capital, compared to just $15 million last year. Moving on to the balance sheet and liquidity as of June 30, 2020, Antero Midstream had $1.16 billion drawn on its $2.13 billion revolving credit facility, resulting in approximately $1 billion of liquidity. AM's total debt was flat quarter-over-quarter at $3.1 billion as a result of the improved free cash flow profile, as well as receiving $39 million of the $55 million cash tax reimbursement under the CARES Act. Looking ahead to the back half of 2020, we expect capital expenditures to continue to decline driving increasing free cash flow before return of capital. As a result, we expect AM's total debt to remain relatively flat at $3.1 billion for the remainder of 2020. I'll finish my comments on slide number one titled, Inflection Point of Generating Free Cash Flow. This slide depicts just how far we've come since our IPO in 2014, where we outsped cash flows by approximately $600 million before return of capital. In 2020, we are now at the point of harvesting those five years of capital discipline investments and leveraging our core gathering, processing and water infrastructure. We have stayed true to our disciplined capital investment philosophy and not made any expensive acquisitions or investments in downstream opportunities that did not meet our return thresholds, or tied up capital and long lead time capital projects. Our just-in-time capital investment philosophy and capital discipline have allowed us to reduce our capital budget by over $100 million in 2020 and target $445 million to $475 million in free cash flow before return of capital. This continued downward momentum in capital spend and our stable fixed fee earnings allows AM to maintain a strong and flexible balance sheet. I'd like to finish the call by thanking all of our employees, who safely delivered an exceptional operational quarter with no material curtailments despite all of the ongoing uncertainty and challenges surrounding the COVID-19 pandemic. With that operator, we are ready to take questions.

Thank you. Ladies and gentlemen, at this time we will conduct our question and answer session. Our first question comes from Jeremy Tonet, with JP Morgan. Please state your question.

Hi, good morning.

Hi, Jeremy.

I would like to begin by discussing our capital allocation philosophy. Even though we received the third joint venture payment for the quarter, the coverage on the distribution was quite tight. I'm curious about our approach to capital return, specifically balancing the 22% yield with the potential for increasing share repurchases or paying down debt. I'm interested to understand what factors influence our current distribution level as compared to possibly lowering it to focus on those alternative options, especially given that buying back units may be more beneficial at this juncture.

Jeremy, we’ve stated our coverage ratio kind of range from the start of 2014, and it's around 1.1 times, so if you did do that $7 million, you would have been at that 1.1 times. So, the quarter was well within our expectations and our philosophy on paying the dividend. The other thing that influences that is when you look at our free cash flow plus that tax payment, there was no leverage added during the quarter. So the return of capital and the dividend was within our free cash flow. And so, we look at that as well. We look at our capital budget through a shift in time. There's no long lead time and it's decreasing so that free cash flow increases over the next couple of quarters. So, that will support the dividend payments. And then you look at our leverage, of course, we're in the mid-three times. So, a very strong balance sheet compared to our peers. So, all of those factors go into when we determine the dividend, and we're comfortable with the level that it was at.

Got it. Just in terms of the absolute level of yield, the 22% seems a bit high there. So I just didn't know if there was a certain level of, I guess, accretion that could be achieved on repurchases where it might make sense to pivot in that direction or if that goes into kind of your thought process in any way?

No, we expect the equity to perform better over time and that yield to decrease to align with the dividend. It was a volatile quarter, and there was some weakness across the entire industry. Therefore, I don't believe that yield accurately represents the true underlying fundamentals of the business.

Got it. Thanks for taking my question.

Thanks, Jeremy.

Thank you. Our next question comes from Holly Stewart with Scotia Howard Weil. Please state your question.

Thank you. Good morning, gentlemen. Maybe just one from me, Mike it looks like the processing capacity was 100% utilized during the quarter. Could you just remind us of the schedule there?

Yeah, so, the next plan and Sherwoods at that capacity with 13 plants and that was at 100% capacity. C3+ is almost entirely complete. And that should come on either later this year or in 2021. But with that said, AR’s kind of out of maintenance capital. They produce around 3.5 Bcfe a day in the second quarter. So there's not much growth going forward. So Sherwood right now has the ability to handle. It's flowing at above nameplate, but still has the ability to handle the volumes.

Okay, great. And then maybe for, one for Paul or Glenn, just on we saw the take-in transaction earlier in the week with CNX and CNX midstream. Just kind of curious your thoughts there?

Yes, I think same here. We share the curiosity. It'll be interesting to watch that transaction. We certainly looked at a combination of AR and AM when we went through the simplification in 2018. As you recall, that was a lengthy process with lots of different outcomes analyzed. And the decision was made for Antero really to separate the governance and convert AM from MLP into a C Corp. So our situation is not really an analogy so just that we'll watch the CNX situation like we said with curiosity. Further, AM is just a much bigger midstream business relative to AR upstream compared to CNX and CNX Midstream. But curious situation, be interesting to watch.

Yeah. Maybe the vice versa AM taking AR.

Thanks for the idea.

That's all I had. Thanks guys.

Thanks Holly.

Our next question comes from Ned Baramov with Wells Fargo. Please state your question.

Hi, thanks for taking the question. Two parts, one on the JV distributions. So first, could you maybe talk about the reason for only two monthly distributions being received by AM? And second, it seems the distributions for the two months were $19 million, which would imply 9.5 per month, while you quantify the impact to EBITDA for the third month to be about $7 million, so if we could just talk about the step down in monthly distributions from the JV?

The first point is simply a timing issue. We only record revenue when we actually receive payment, and we only received payment for one of these quarters later on. There will likely be a catch-up payment, but it's difficult to predict for now. Regarding the difference between $19 million and $7 million, it's typically around $21 million a quarter for the three months. When we budgeted, we anticipated $7 million a month, and that $7 million likely reflects the current volume, which is higher than what we had forecasted. It probably would have been closer to $9 or $10 million. However, the $7 million was what was actually included in the forecast.

Got it. That's helpful. And then maybe just switching gears on your supply-demand analysis of the North American gas market. Maybe could you just talk about your view on the development of the Haynesville as opposed to the Northeast to fill in the supply reduction from declining production in most other basins?

I think we've observed a decline in Haynesville. The latest figures I encountered showed production falling from 13 Bcf a day to below 11 Bcf a day in just a few months. I'm not sure why this is happening. We view Haynesville as less economical compared to top gas basins like Appalachia. Is it simply a matter of capital allocation? We're monitoring the situation closely. It has been puzzling for many in the industry how Haynesville has maintained such high levels for so long. While I don't have a definitive answer, it likely doesn't come as a surprise to the industry that production is declining compared to some other gas basins.

Got you. And then last one for me if I may. Are there any updates on the litigation with Veolia that you could share?

There are no updates.

Thanks. That's all I had. Thank you.

Thank you.

Thanks Ned.

Our next question comes from Sunil Sibal with Seaport Global Securities. Please state your question.

Yes. Hi, good morning, guys. And thanks for all the clarity. I just wanted to go back to the Slide 9 in your deck where you talk about the infrastructure build-out and the differentials between, say, Northeast and Mont Belvieu. So seems like, second quarter there was probably one-time items and then the regional demand is probably also be the corridor. In addition to the new infrastructure which you talked about the pipeline capacity being expanded, are there other factors that you think would lead to tightening of the Belvieu to the Northeast spread?

The primary driver is the Northeast's early stage, which has always been priced higher than Belvieu. The market has been short on NGLs for refinery needs, including gasoline blending for butanes and pentanes, as well as propane for the competitive market. Appalachia has grown significantly, creating a need for export outlets to alleviate supply issues, which we have emphasized repeatedly. The impact of Mariner East will influence the pricing floor in the basin. We anticipated a price decline even before Mariner East started operations, and the results over the past year and a half have aligned with our expectations regarding how it would affect the pricing floor once obstacles were removed.

Got it. And could you remind us on the transport side, you obviously have capacity on Mariner East, than in terms of locking in the far east or the European prices? Do you have contracts on the shipping side also?

We have indexed sales to the Far East Index and the Northwest Europe, but we have not ourselves actually charted the vessels, so we are predominantly selling FOB the markets hooked up dock, but at either a Mont Belvieu ARA or FEI linked price. And so when you sell versus an international index, you can somewhat imply what your shipping cost was in the price that you sold the dock at.

Okay, got it. And then one kind of broader question on the leverage and the dividend coverage philosophy. So it seems like, I think in the past you've articulated 1.1X to 1.2X kind of dividend coverage where you're comfortable with and leverage also 3.5X to 4X. So obviously you're staying within those kind of broader parameters at the same time de-risking the overall AR complex of Antero complex. Should we think about you kind of revisiting those parameters at some point of time, obviously if you execute on AR kind of debt reduction strategy, considering that the midstream industry overall has kind of moved beyond those kind of numbers and kind of pointing to more conservative parameters on those two criteria?

Nothing at this time, I think the mainstream industry is trying to get down to our balance sheet or in fact, in the mid-three. I do see some of those coverage ratios going higher for other midstream providers, but that's generally because they may have long-term capital projects or other kind of calls on their cash, that Antero Midstream doesn't have. So right now we're comfortable in those ranges that you mentioned.

Okay, got it. Thanks.

Thanks, Sunil.

There are no further questions at this time. I'll turn it back to management for closing remarks. Thank you.

I'd like to thank everyone for participating in today's conference call, if you have any further questions, please feel free to reach out to us. Thanks again.

Thank you. This concludes today's call. All parties may disconnect. Have a good day.