Antero Midstream - Earnings Call - Q3 2020

Transcript

Speaker 0

Greetings, and welcome to the Antero Midstream Third Quarter twenty twenty Earnings Conference Call. At this time, participants are in a listen only mode. A question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to Michael Kennedy, Chief Financial Officer.

Please go ahead, sir.

Speaker 1

Thank you for joining us for Antero Midstream's third quarter twenty twenty 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 and A. I would also like to direct you to the homepage of our website at ww.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'd 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 Conalongo, Vice President of Liquids Marketing and Transportation. With that, I'll turn the call over to Paul.

Speaker 2

Thanks, Mike. I'd like to start by highlighting the progress AR has made on its asset sale program in 2020 beginning on Slide three titled AR Asset Sale Refinancing and Debt Repurchase Update. To date, AR has executed $751,000,000 of asset sales, achieving the bottom end of its $750,000,000 to $1,000,000,000 asset sale target. These transactions have allowed AR to reduce its near term maturities by $1,300,000,000 since initiating the asset sale program in the 2019 and positions AR to repay its 2021 and 2022 maturities. AR continues to monitor various asset sale markets and any additional proceeds will be used for further debt reduction.

The current natural gas and NGL fundamentals continue to look encouraging as we head into 2021, as Dave Canalongo will discuss in his comments. This further supports upside to AR's free cash flow profile driven by the scale AR has achieved over the last several years. To put it in perspective, as the second largest NGL producer in The U. S, every $5 per barrel change in C3 plus NGL prices improves AR's annual cash flow profile by over $225,000,000 On the natural gas side, AR is 100% hedged in 2021, but the improving gas strip increases AR's underlying value and opportunity set. Now let's turn to Slide four titled AR firm transportation provides stability.

The red line in the chart represents the Appalachian basis differential, which has averaged $0.82 below NYMEX going back to 2014. AR's premium Feet from transportation has delivered a $05 discount to NYMEX over that same timeframe. It is also worth noting that since AR has had access to its entire Feet portfolio in 2018, it has been able to realize a $06 premium to NYMEX to date. During the third quarter, this benefit was even more pronounced as Appalachian basis differentials blew out and regional prices traded at 1.5 below NYMEX. As depicted on the slide, AR's Feet portfolio provides pricing stability and production flow assurance, derisking AR's business model.

It effectively provides an insurance policy that protects physical gas flow and allows AR to hedge liquid NYMEX Henry Hub prices. This has allowed AR to avoid shut ins and curtailments experienced by other peers in Appalachia and in turn, it drives stability and reliability for AM's revenue stream. Lastly, I would like to briefly discuss AM's corporate sustainability report, which highlights our outstanding environmental, social and governance or ESG performance on Slide five. Since its inception, Antero Midstream has been committed to environmental excellence and our greenhouse gas intensity is one of the lowest in the industry. Our methane leaf loss rate of 0.017% in 2019 was significantly below the One Future industry and sector targets of one percent and zero point two eight percent, respectively.

Looking forward, we believe natural gas will be key to the energy transition in the coming decades as a complement to renewable energy growth. As one of the largest natural gas gathering and processing midstream companies in The U. S, we are well positioned to maintain our peer leading ESG position, while striving to improve our metrics even further through our 2025 environmental targets. On the governance front, in 2019 Antero Midstream transitioned away from the MLP structure to a full C Corp structure, significantly enhancing shareholder rights and improving corporate governance. Our Board is comprised of a majority of independent directors and our compensation plans are based on metrics aligned with shareholder value, including return on invested capital, leverage, ESG metrics and per share cash flow growth.

With that, I'll turn it over to Dave Canalamdo.

Speaker 3

Thanks, Paul. Let's turn to Slide number six and begin by adding some color on the NGL and LPG macro environment. In the aftermath of the March OPEC plus price war and the COVID-nineteen pandemic, the resulting decline in rig and completion crew activity basins in has set up expectations of a prolonged period of depressed U. S. Oil production.

Thus far, that is what has materialized, a decline in flattening of oil production, which has resulted in a decrease in associated NGL production from the oil focused plays. The chart on the left hand side of the slide illustrates that U. S. NGL supply forecasts have declined by 1,100,000 barrels per the beginning of this year. We believe it may take three to four years for U.

S. NGL production to return to pre COVID-nineteen levels. The chart on the right hand side of the slide highlights the expected surplus of LPG export capacity along the Gulf Coast. Since the start of the shale revolution, we have enjoyed only a handful of periods when ample export capacity has been available. Looking forward, plentiful dock capacity will allow The U.

S. To fully access the international markets on a sustained basis, resulting in U. S. Mont Belvieu prices closely linked to international markets. While Antero has enjoyed unrestricted access to these international markets through our Mariner East commitment for nearly two years now, this fundamental change on The U.

S. Gulf Coast will benefit Antero share of NGL production that is sold domestically and linked to Mont Belvieu pricing. Turning to Slide 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 resilient petrochemical and residential commercial markets during this pandemic. Here we illustrate the outperformance of Mont Belvieu C3 plus pricing relative to WTI in 2020.

On the right, we see the continued outperformance of propane relative to Brent at the Far East Index or FEI, which is the benchmark in Asia. What we've witnessed is that demand for LPG in key Asian markets during the third quarter has actually increased year over year and that the strength of NGLs witnessed early in the pandemic was not temporary. Looking beyond the resilient residential and commercial demand, the relative preference of gasoline in the global transportation fuels market during this pandemic has also been favorable for NGL pricing on a relative basis to oil. Gasoline has been less effective than distillates, which have seen inventories increase significantly due to the more pronounced and prolonged decline in jet fuel demand. Resulting weak distillate demand has led to reduced refinery runs in The U.

S. And globally, which in turn has lowered the production of refinery LPG and other gasoline blend components such as naphtha. Ultimately, these downstream trends have been even further supportive of blending butanes and C5 plus into the gasoline pool. In addition, the relatively tighter supply and demand dynamics for naphtha has a knock on effect for LPG as there is some competition between naphtha and LPG for use as a feedstock in select steam crackers in Europe and in Asia. Overall, we believe that global market dynamics are constructive for NGL prices at a minimum in the near to mid term timeframe.

Turning to Slide number eight titled NGL Pricing Outlook. The chart illustrates the value that some third party analytical teams, including the Citibank commodities team shown here continue to place on NGLs in 2021 and beyond based on their bottoms up global supply demand models. Behind many of these forecasts is the realization that if oil was to stay range bound throughout 2021 at $40 to $45 a barrel, the world will simply not be able to supply enough hydrocarbons in the subsequent years to meet demand in a post pandemic environment, which undoubtedly will result in higher prices. Looking more closely at the Northeast takeaway capacity, Slide 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. Realized Northeast differentials continue to improve year over year with more and more volume shipping out of the basin on the Mariner East system as Energy Transfer has added incremental capacity since initially placing Mariner East two in service.

With the Northeast LPG supply potentially at its peak here in 2020, we ultimately expect Northeast differentials to Mont Belvieu to strengthen even further in coming years. With that, I will turn it over to Mike.

Speaker 1

Thanks, Dave. I'll begin my AM comments with third quarter operational results beginning on Slide 10 titled Year Over Year Midstream Throughput. Starting in the top left portion of the page, low pressure gathering volumes were 3.1 Bcf per day in the third quarter, which represents a 13% increase from the prior year quarter. Compression volumes during the quarter averaged 2.8 Bcf per day, a 16% increase compared to the prior year. AM added $120,000,000 per day compressor station in the Marcellus and compression capacity was 90% utilized during the 2020.

Our fifty-fifty joint venture gross processing volumes averaged 1.5 Bcf per day, a 43% increase compared to the prior year quarter. Processing capacity was over 100% utilized during the third quarter. JV gross fractionation volumes averaged 39,000 barrels per day, a 22% increase from the prior year. JV fractionation capacity was 98% utilized during the quarter. Freshwater delivery volumes averaged 111,000 barrels per day, a 21% decrease from the prior year quarter, driven by lower completion activity by Ontario Resources.

Freshwater delivery volumes were ahead of expectations during the third quarter driven by an acceleration of completions as AR averaged a company record 8.5 completion stages per day. This pulled incremental stages into the third quarter originally scheduled for the fourth quarter. And as a result, we expect a reduction in freshwater delivery volumes in the fourth quarter. Moving on to financial results. Adjusted EBITDA for the third quarter was two twenty nine million dollars a 5% increase compared to the prior year quarter.

Distributable cash flow for the third quarter was $189,000,000 resulting in a DCF coverage ratio of 1.3 times. Capital expenditures during the quarter were $37,000,000 a 77% decrease compared to the 2019. During the third quarter, we generated a company record $158,000,000 of free cash flow before return of capital compared to just $23,000,000 in the prior year quarter. Moving on to the balance sheet and liquidity. As of 09/30/2020, Antero Midstream had $1,190,000,000 drawn on its $2,130,000,000 revolving credit facility, resulting in approximately $950,000,000 of liquidity.

AM's total debt and leverage were both flat quarter over quarter at $3,100,000,000 and 3.7 times respectively. I'll finish my comments on Slide 11 titled AM Updated Guidance Summary. As depicted on the slide, we have taken significant steps to reduce capital investments by over $100,000,000 compared to our original budget, a 34% decrease. Driven by throughput exceeding expectations and operating expense reduction achieved to date, we increased our adjusted EBITDA guidance from the previous range of 800,000,000 to $815,000,000 to $835,000,000 to $845,000,000 These two factors have driven a $90,000,000 or 23% increase in our free cash flow guidance in 2020 at the midpoint of the revised guidance range of $485,000,000 to $495,000,000 In addition, we are currently trending towards the higher end of our return on invested capital target of 14% to 16%. Our just in time capital investment philosophy has positioned us to quickly adapt to changes in AR's development plan and avoid being overbuilt on midstream infrastructure.

All of these achievements would not be possible without the hard work and dedication from all of our employees who safely delivered another exceptional operational quarter. With that operator, we are ready to take questions.

Speaker 0

Thank you. We'll now be conducting a question and answer session. Our first question today is coming from Jeremy Tonet from JPMorgan. Your line is now live.

Speaker 4

Hey, good morning, guys. This is James on for Jeremy. I guess just started off with 2021 and understand it's early to provide any numbers there. But I guess just given the revised guidance for 2020 and what that assumes for 4Q, would it be fair to assume that 4Q might be a good annualized run rate for 2021 just assuming Antero stepping down activity here?

Speaker 1

No. I mean it would be at least on the revenue side probably okay. But Antero Midstream had a couple expense items in 2020 that will not repeat in 2021 and that's specifically around the Clearwater facility. And then also on the remains to be seen, but the rebates step up in 2021, the threshold levels. So some of those may or may not be achieved whereas in the 2020 timeframe and in fourth quarter we expect those to be achieved.

So EBITDA should be higher than that kind of fourth quarter run rate.

Speaker 4

Got it. That's helpful. And then just shifting to kind of the debt profile here. It seems like it's been trending a little bit higher in the past few quarters. Can you just talk to me about what you expect in terms of the pace of deleveraging next year?

I know you guys have mentioned you're comfortable within this kind of three to four times range, but just wanted to see if given the free cash flow inflection, if you can see that leverage ticking lower next year?

Speaker 1

Yes, I don't know what you're referring on the second and the third quarter. We actually paid down a little bit in the second quarter. In the third quarter, we only increased leverage by $30,000,000 and that's because we have our interest expense of actual cash interest paid occurs in March and September of every year for $60,000,000 versus an interest expense of $30,000,000 So we actually had free cash flow above the return of capital this quarter. I think it was 147,000,000 about $10,000,000 worth. So that's the first time.

So now we expect leverage to be flat when we look at the models going forward. We don't add any absolute leverage. It stays flat. And with EBITDA ticking up a little bit that 3.7 times trends a bit lower, but kind of stays in the mid-3s level.

Speaker 4

Got it. And then one more if I can, just more on a macro one, but obviously given the takeover of the basin, you have the Atlantic Coast cancellation, there's MVP hurdles remaining. I guess just looking at next year, what's really the impact if maybe MVP is delayed on the AM business?

Speaker 1

For me, I think that would be encouraging for AR. Obviously, AR has the firm transport already in place to deliver its production to the premium price markets. So any widening in basis does not affect them from a production flow assurance from a throughput in the AM systems, but it probably allow AR to have lower marketing expense, would improve just their overall financial profile.

Speaker 4

Got it. Thanks a lot for me.

Speaker 2

Thanks, James.

Speaker 0

Thank you. Our next question today is coming from John McCabe from Goldman Sachs. Your line is now live.

Speaker 5

Hey, everyone. Good morning. Thanks for the time. Just wanted to circle back on two of those actually just asking a little bit different way. The 2020 guidance implies a bit of a step down for 4Q 'twenty.

I understand that AR production is going to step back a little bit. But is there anything else moving there, maybe a one off on either side?

Speaker 1

No. I mean, one thing I mentioned in my comments, you probably about half the completion activity that we had in the second and third quarter on the water. And so when you look at that, I think the water EBITDA for this quarter was in between 30,000,000 and $35,000,000 So half of that would suggest next quarter's water EBITDA would be 15,000,000 to $17,000,000 So that's part of the primary step down. And then you do have a little bit lower about $100,000,000 a day lower volumes of throughput. So those two in combination gets you to that implied EBITDA kind of at the midpoint in the fourth quarter of 195,000,000 to $200,000,000

Speaker 5

Great. That's helpful. Thank you. And then my follow-up is actually so didn't use the buyback this quarter, but could you guys just share how you think about using the buyback going forward and whether or not you might consider increasing leverage even just temporarily to buy back shares?

Speaker 1

Yes. No, we wouldn't consider increasing leverage to buy back shares. We still have $150,000,000 available to us, and we're just opportunistic around that. But we definitely take into account our leverage and do not want to increase our leverage for buybacks.

Speaker 5

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

Speaker 2

Thank you, John.

Speaker 0

Thank you. Our next question today is coming from Greg Brody from Bank of America. Your line is now live.

Speaker 6

Hi, guys. Just a clarification on the midstream fee incentive, which was hit this quarter, which you've I guess you paid AR. Do you expect that to occur in the fourth quarter as well? It's Yes. You do.

And that's in the numbers. And there's no delay in that, that happens. So if it was in the third quarter that happened, you paid AR in the third quarter for it? Did you actually

Speaker 1

pay We it fourth them in October.

Speaker 6

October. Okay. That's it for me. Thanks for the time.

Speaker 0

Thanks, Greg. Thank you. Our next question today is coming from Sunil Sibal from Seaport Global Securities. Your line is now live.

Speaker 7

Yes. Hi. Good morning, guys. Thanks for First taking my question was related to the NGL volumes that you processed with your JV. Seems like there was a pretty decent pickup sequentially in that number.

Is that anything to do with how you're recovering NGLs? Or because the processed volumes were up 6%, but the NGL flows seems like were up more. So just trying to understand that.

Speaker 1

No, nothing different. It was just from the production growth at AR and it being focused on a heavy liquids window of the Marcellus.

Speaker 7

Okay. And then on the consolidation front, obviously, the E and P sector is seeing some consolidation effort. I was curious how your what your views are around consolidation in the midstream side. I think in the past, you guys have talked about growing third party business. I was wondering if you could frame for us any opportunities or how do you see that playing out?

Speaker 3

We're still focused on organic the organic business, but we definitely keep our eyes open for opportunities. And I don't think there's anything near term, but we'll keep evaluating anything that comes up in the basin. And we generally have shied away from situations where we buy into gathering driven by another producer. So that's not really been of interest. It's been more looking at downstream opportunities.

Speaker 7

Got it. Thanks.

Speaker 2

Thank you. Thank you, Sunil.

Speaker 0

Thank you. We've reached end of our question answer session. I'd like to turn the floor back over to Michael Kennedy for any further or closing comments.

Speaker 1

I want to thank everyone for participating in our conference call today. If there are any further questions, please feel free to reach out to us. Thanks again.

Speaker 0

Thank you. That does conclude today's teleconference. You may disconnect your lines at this time and have a wonderful day. We thank you for your participation today.