Antero Midstream Corporation (AM) Earnings Call Transcript & Summary

Good morning or good afternoon, depending on where you're located. Thanks for joining our virtual fireside chat with Antero Midstream. I hope you and your families remain safe and well. [Operator Instructions] It is my pleasure to be joined virtually by Glen Warren, President and Director of Antero Midstream and CFO of Antero Resources; Dan Katzenberg, Finance Director; and Justin Agnew, Finance Director. Gentlemen, thanks for dialing in.

I will start with a few questions on Antero Resources, AR. It feels the company's position has improved significantly over the past 12 months, asset sales, debt repayment, a borrowing base redetermination above current commitments, CapEx and OpEx reductions. Now that you have also redeemed the 2021 maturity of AR, could you maybe talk about the company's ability to access debt markets to refinance 2022 and 2023 maturities?

Yes, Ned, thank you for the question, and a pleasure to be here today. We appreciate it. I think it's just a matter of time in terms of AR accessing the high-yield market on an unsecured basis. You mentioned a lot of the progress we've made. We started the year last year with an asset sale program and executed on that, sold some $750 million of assets, which led to our ability to access the unsecured market on the convertible senior note side, which we did in August. That senior note has traded very well. It was a $288 million deal. And those bonds are trading and those converts are trading at 114 or so. So that's been very successful. So we have great access there. And then, of course, we did -- the complex did issue an unsecured bond here a few weeks ago. AM, Antero Midstream, issued a bond very successfully, well oversubscribed. It was a 7 7/8% coupon. And that bond is trading over par 101.5, 102, something like that these days. So that's done very well. So we've really kind of, I think, laid the bricks on the road to get there to the unsecured markets. For AR, AR's, long bond is trading sub-10% yields now. That's a 2025 maturity. And so it's all stacking up very well. You've got great momentum with NGLs. On the NGL side, we've seen NGLs go from a low of $15 a barrel for our C3+ barrel in the second quarter of the year to $22 a barrel in the third quarter. And now we're looking at $27, $28 a barrel today on a weekly basis for our NGL barrel. So that's tremendous upside. We tend to -- for every $2 change in our C3+ price, that yields about $100 million of cash flow on an annualized basis. So every $2 uptick is very meaningful to us on an annualized basis. So it all looks much better looking at next year with expected free cash flow over $200 million for AR, which'll be going to repayment of debt. So all very favorable. And I think the market, as we enter the new year, will be wide open to investors looking for alpha on the high-yield side. So we're excited to be back in that market, hopefully, in the near term.

Okay. Great to hear. And maybe if you can just talk about the latest feedback you may have gotten from your lenders on potentially extending the credit -- revolving credit facility of AR.

Yes, great question. Tremendous support from the bank group in general. We have 25 banks. There is a subset of those banks that are -- some of them are leaving the lending business to upstream. And so, through no fault of Antero, it's just their exposure across the space, they're electing to either reduce or eliminate that exposure over time. Some are selling their old buck to other banks. So there's some disruption for a portion of our bank group. So we don't deny that, but the rest of the bank group, very solid. We'll talk about ESG at some point in a little more detail probably during the call, but we have very strong ESG metrics. The lead banks are very attracted to that. They want to loan more to companies like Antero with strong metrics there. That's the future we all think and sort of the energy transition. So we feel good about all that, and time will tell. But will the bank facility, the commitment level be lower than it is today, the $2.64 billion, I think that's certainly possible, given the disruptions in the bank market. We will probably renew that facility in 2021 at some point, at least by the fall of 2021. So we will be in the market and discover that. But it's still there for us, no doubt about it. Will it be a 5-year deal? Don't know. I think time will tell. All those tailwinds that we've talked about have really helped in that sense. So we're optimistic, but we want to make sure we're active in the bond market and a significant part of our debt is actually turned down in bond market versus being reliant on the borrowing base and a shorter-term money.

Got it. And maybe last on this topic, has there been a change in how rating agencies assess the risk profile of the Antero complex?

Well, I think to the positive. This year, we met with the rating agencies back in sort of the July, August time frame just to show the progress, the asset sales and such. And then we did the convert, of course. And that was all very attractive to them. I think Antero may have been the only upstream company that got upgraded by Moody's there in September, and so that's been very positive. They recognize the fact that the commodity outlook has improved dramatically for us. They recognize the fact that we have addressed those near-term maturities to a great extent. We took steps and executed on it. We didn't sit on our hands. And so that's all very attractive to the rating agencies, and they roll out that our focus is debt repayment. So I think we're in good stead with them. And I think Antero AR and AM's ratings are essentially capped by AR's ratings given the relationship. So I think it's all about AR and its improvement, but generating nice free cash flow next year, and hopefully, we get good access to the bond market. If you look at the metrics, AR is a solid BB company. That's where we were. And really, what took us down was those near-term maturities and the unutilized FT, which we're addressing as well. So I think the progress is all good and up into to the right, and we're very optimistic about next year despite the fact that gas has cratered here in the -- on the futures curve on the front end just due to lack of weather and a little bit more supply than some people expected. But we think the long-term fundamentals are really good for gas. And by the way, AR is almost 100% hedged on gas next year at almost [ 2 80. ] So very good prices relative to the prices today. But we think 2022, 2023 looks really good for natural gas. And NGLs are just rock solid, I think, because that's been very resilient demand base there. So I think with that commodity outlook, it really helps with the rating agencies. So I think it's -- hopefully, it's all up into the right from here with the ratings.

That's helpful. And then on the macro side, I guess you touched a little bit on this, but you have a view that lower activity in crude-directed basins reduces the supply of associated gas and NGLs, which in turn improves prospects for gas producers. Given some of the recent recovery in crude prices and vaccine optimism, what are your thoughts on the trajectory of associated gas and NGL production in the next 12 to 24 months?

Yes. I was afraid that thesis could be used against us at some point, Ned. That's bound to happen. But I do think of it as a bit of a teeter-totter, if you will, an old term. But the higher oil prices go, the more likely you're to see more activity in the oil-directed basins, which brings more associated gas and more NGLs with it. And that's certainly been the thesis this year that as prices dropped into the 30s that you're going to really dampen activity, and you saw that. Now it has been climbing back steadily over the last several months, the rig counts, the completion activity, but still nowhere near where we were. So I think it is a fairly flattish production profile overall expected for associated gas and NGLs over the near to medium term over the next 2 to 3 years, which really lends itself to strong natural gas and NGL prices. I think -- and we're not wishing against oil prices because C3 is tied to oil to some extent, certainly, within a band. And so that's important to us. We want good oil prices and good NGL prices. But I think the Goldilocks scenario for us and other companies that have NGLs -- natural gas-oriented but have NGLs, is something in that mid-$40 range. That's a good price deck to where you're going to see activity certainly in the Permian and the better oil-directed basins. But you shouldn't see a whole lot of growth. I think the market is looking for discipline there as well, just like it is with the natural gas producers. So I think the -- as a betting man that you won't see a huge growth in associated gas in NGLs over the next couple of years, which bodes really well for us. I mean if you look at OPEC spare capacity, I think it's in the 7.5 million barrel a day range. That's quite a bit of spare capacity. With economic recovery, sure, some of that will be needed. But I think there's also some long-term damage to demand for oil that comes out of all those, too. So we feel like prices are going to be moderate on oil, and our thesis will play out nicely for NGLs and natural gas. But no doubt, if WTI went back to $55, $60 a barrel and Wall Street's funding oil-directed producers like crazy, then you get back over time to where you were a couple of years ago, or 2019 even, with too much gas supply and a lot of it not really sensitive to gas prices. So we hope we don't get back to that scenario anytime soon, but time will tell. There's definitely a relationship there.

Sure. And then at what price for gas or actually NGLs would AR consider deviating from the current path of flat production? And then, I guess, secondly, would a hypothetical growth scenario be considered by AR prior to achieving its leverage target?

Yes, that's a great question because we love answering that question because we're very -- we're adamant about it. Our Board's are adamant about it that every dollar goes to debt repayment. We just -- despite perhaps a price spike in NGLs, say, NGLs went to $30 or $35 a barrel over the next 6 months, we would just capture that cash flow and repay debt even faster. That tremendous leverage of the $2 change yielding $100 million of annual cash flow, you can really repay debt quickly that way. But we really need to see debt at AR go from $3 billion range at year-end this year -- and I'm just building in expected free cash flow for the fourth quarter. I think we've got all that on our website, but $3 billion year-end, we'd like to see that go below $2 billion before we think about any real growth at AR. So I think you'll see us as very disciplined at AR in terms of maintaining flat production. I think we will look at some of the -- we do have some excess firm transport, no doubt, and that does roll down over time. But are there some things we could do with third-party producers, let's say, to bring on more gross gas production to flow through that FT and eliminate that unutilized net marketing expense at AR? And I think there are some things we can do there, and that would be certainly positive for AM if we were to do something like that from a throughput standpoint. But otherwise, AR on a net basis, expects to stay with flat production, maintenance capital for the foreseeable future. So I don't see us flinching and reacting to a price change by throwing more rigs or more activity at it.

Got it. And you mentioned the firm transportation capacity at AR. Can you maybe talk about the secondary market for pipeline capacity in the Northeast? We've seen ACB canceled and then MVP delayed. So one would assume AR is now in a better position to potentially some of that capacity or just take advantage of marketing opportunities. I believe you've been active on both of these fronts, reselling capacity on marketing stranded gas. But could you maybe comment on whether there are any opportunities to sign longer-term contracts on some of the excess FT capacity you hold?

Yes, that's a great question, and we do have excess FT today. There are a couple of slides in the AR website presentation in December that I would refer people to. There's one on Page 30 in that presentation that just shows the firm transport does step down over time over the next several years, and we expect $100 million or so over the next 4 years of -- on an annual basis of net marketing expense to go away just because of that step-down. So it kind of naturally happens. Today, some of that excess capacity, we do utilize by buying third-party gas when there's a spread. So you have to have a spread where it makes sense, where the spread is higher than the variable cost on the pipe for us to buy third-party gas, move it through the pipe to a better market and capture that spread. Sometimes we share the spread with a third-party producer, sometimes not. It just depends on the situation. But we're generally picking up 200 or 300 million cubic feet a day when there's a spread there. So that does help reduce that net marketing expense that we forecast. So it generally does come down with that. And on to your main question of how easy is it to -- it's fairly easy to market FT on a short-term basis. There are plenty of large marketing companies out there that like to do AMA transactions, where maybe for a winter period, 4 or 5 months, they'll take capacity off our hands and pay some portion of the demand fee to us for that. And so we do often do that. We have some of that in place for this long term. It reduces our demand fees on the pipe where they're taking out the capacity for a short-term period. We have found, however, that it's been difficult to market long-term commitments on pipes, whether to marketing companies or even other producers. And that's partly due to the period that we've been through. If you look at -- it's hard to refer to a different book, but we have a nice page in the AR website book for December, Page 32. I'll refer people to where we're showing the overall capacity in the basin. And so that capacity really spiked up in the 2018 time frame with the nexus coming in service and Leach Express and Mountaineer Express and Rover. So tremendous uptick in capacity. And we really needed that because we've been seeing basis differentials in the $1 to $2 range even for Dominion South and M2-type market. So if you were marketing locally, and a lot of producers have been, and we have the early firm transport, so we stayed away from those kind of basis blowouts. But all that new capacity really dampened that volatility. And that's been great for producers over the last couple of years in Appalachia, where they've had pretty reasonable basis in the basin. So during that period, investors looked at us and said, "Gosh, you've got too much firm transport. Even with your growth, it's going to take you a while to fill it." And it became a big negative bear thesis on AR. Well, I would proffer that that's flipped now because if you look at the production on Page 32 in the AR book, it's right up bumping up against the takeaway capacity in the basin. So when that happens and you get into a seasonal -- a shoulder season like we have just been through September, October, even November of this year, where you have some pipeline maintenance and there's not much local demand, well, all the molecules are trying to get out of Appalachia and basis widen. So we had basis blow out again here out to the $1.50, $1.60 range even over the last few months. And so we happily were able to move all of our gas molecules sort of bridge over that swap in the Appalachia basis blowout. Because we had all this firm transport, we could move our molecules. And so I think our basis differential was slightly negative in the third quarter, but it was what a few pennies off of NYMEX. Whereas other producers, many were $0.40, $0.50, $0.60 off of NYMEX. And that was after they curtailed a bunch of production to manage that. So it would've been even worse if they kept producing. So you're seeing that it's gotten pretty tight again, shoulder season, especially when you have pipeline maintenance or other issues. So we're pretty full up now is the message. So I would say that our FT has now flipped back to an asset from a liability. It was treated as a liability conceptually over the last couple of years. So we're really the only producer who has the potential to grow, and that's why I mentioned maybe there's some third-party opportunities to either market the -- some of the volume or some of the takeaway -- excuse me, or bring in the drill bit of others potentially to drill some wells to add a wedge to fill that firm transport. And then MVP is kind of the wildcard. The assumption is that gets put in service second half of next year, but they still got some regulatory hurdles to cross. And with the administration changing, just don't know how that's all going to play out. It's needed in Appalachia. As I said, we're fairly full up today. The expectation, as that comes on that's -- if you look at the futures market for Dom South and TETCO M2, it's trading in the -- call it, the $0.40 to $0.70 range depending on the season. Well, that's expecting MVP to be in place and to provide more takeaway. If that doesn't happen, I think those futures markets for basis will flow out again. So that's kind of a lay of the land, the long-winded story.

Thanks for this. And then changing topics. Let's spend a minute on CapEx. So this year, you've demonstrated an ability to significantly pull back on spending at both AR and AM. And I believe this has been largely due to: one, your maintenance program; two capital efficiencies; and I think, three, the design of your development program at AR, which has been more focused on staying closer to existing AM infrastructure. Looking at your 2021 CapEx target at AM, it implies an even lower budget relative to 2020. So 2 questions here. How sustainable are the CapEx efficiencies you've realized to date in the long run? And how long is the development runway at AR before you have to move further away from AM systems, which may require additional midstream spending?

Yes, that's a great question, Ned. I'll answer the first part of it, and maybe Justin can answer for the AM side, sort of the outlook over the next several years. But yes, it's been a tremendous year from an efficiency standpoint. And so much of what we've done -- some of it is detailed on some of our pages in the AR presentation, particularly. But some of it's logistical things like sourcing sand closer to the well pad. And some of it, a big portion of it has been changing the way we deal with water. We were purist on water forever in terms of wanting to use freshwater. We built a big freshwater system, which has eliminated 600,000 trucks last year to get to locations. So we haven't trucked a barrel of water in probably 5 or 6 years because of that freshwater system. That's terrific. But we stayed away from recycling. So about 1.5 years ago, we started to switch to blending or recycling lightly, treating at the well side or very nearby and using the flowback and produced water in the next completion. So really completing pads fairly close to each other, kind of mowing the lawn, if you will, across the acreage. And it just makes it very efficient if you use that water the next completion treated lightly, which AM handles all that and is paid a fee for that. But it really reduces the cost for AR, the cost of trucking water away from locations to either inject, reinject or to treat more deeply like at our Clearwater facility, which we shut down. So that's been going on for 1.5 years, and that was a tremendous cost savings for AR. And then just drilling efficiencies, you can see some of the pages in our materials, how now we're averaging over 6,000 feet a day when we're drilling the lateral. So -- and we've had broken records on that, 11,000 feet a day for the lateral for 24 hours. So tremendous drilling efficiencies, completion efficiencies. We've gone from 4 or 5 stages a day, to now, averaging about 9 stages a day. We're completing wells. So all that combined in the aggregate, along with many other little things, have taken over $3 million out of our well costs over the past year, 1.5 years. So we're now down to -- if you think of it on a lateral foot basis $675 a foot. We have some initiatives underway. We think we'll take that into low 600s per foot. And remember that our numbers, when we quote that, we're including about $80 a foot of facilities from pad costs and that a lot of operators don't. They're just talking about drilling completion costs. So we do include some of that in there. So today, we're really around $600 a foot. So I think very sustainable. We would say over 80% of those cost reductions are sustainable. Their efficiency cycle changes, leaving less than 20%, subject to -- of the change subject to reinflation in the service market over time. So we feel very good about that next year, that maintenance capital number for next year, under $600 million at AR for D&C side of it. And then maybe, Justin, you can talk about, as we develop that way over the next 2 or 3 years, how does that capital look.

Yes. In 2020, AM has really benefited from the visibility on the AR development plan and been able to kick out some projects -- defer projects just because our investment philosophy is just -- that just-in-time capital investment. So when we look ahead to 2021, we do see a reduction year-over-year, initially targeting a capital budget of $175 million to $200 million. Some of that reduction is just a reduction in joint venture capital spending on processing and fractionation. But just because of that just-in-time nature, we continue to have high utilization rates. Our compressor and processing utilization rates are 90% to 100%, so we don't have a lot of excess capacity and where that's stranded. So it's highly efficient capital, again, just for the reason that Glen mentioned that all of the build-out really over the next several years is into Tyler and Wetzel County. So included in the 2021 capital budget is some kind of geographic build-out into Tyler and Wetzel County. So when we think about kind of 2022, you're again in that kind of $175 million to $200 million range. But once you get that geographic build-out and trunklines in place, you do see that capital trending down over time in the 2023 and 2024 time frame.

Got it. And then, I guess, shifting gears here a little bit to the latest view of AR on its AM ownership, and then if you could maybe share some of the Board's views on maintaining the current dividend at AM.

Yes. AR is very comfortable with its ownership at this level. It's not planning to sell down the ownership, even though we did sell down some a year ago in December. I don't think that's a big initiative right now, but never say never. It could happen. That kind of comes down to negotiations between the Boards and all that. As far as the dividend level, it's something we look at every year. This past year, we felt like we should stick with the dividend without any real deep analysis because it was supporting -- partly supporting the borrowing base at AR through a very difficult bank period in 2020. This year, I don't think that's the case. AR's borrowing base is well in excess of -- its actual borrowing base is well in excess of the $2.85 billion that was released. It's just the banks in this market, as we talked about the banks earlier, it's difficult to get a borrowing base increase done in this market. But I can tell you that we have plenty of coverage over that $2.85 billion with the commodity price improvement that we've seen. So all that's in great shape. So I think now AM can begin to look at the dividend policy again in terms of leverage and not wanting to increase leverage, wanting to be at least net leverage-neutral and having a target in the mid-3s. And so we'll take a fresh look at that, at the Board level here over the next few weeks and months and have the appropriate dividend policy going forward so that we have good coverage and leverages in check, and we cover the dividend, free cash flow, ultimately.

Got it. And then maybe just one last question. In relation to your appetite at AM to pursue third-party acquisitions. Maybe if you can talk about the type of asset that would be of interest to you and maybe how active is the M&A market process that fit your acquisition parameters.

Yes, that's a great question. I think you'll see more consolidation upstream across the board, but I think in Appalachia, you'll see more. And it's looking for scale, eliminating G&A, operating synergies, all the likely suspects. But to -- and we look at M&A all the time, it's just that we historically have done very little of it because corporate M&A is hard. It's hard to make it work and make it really value-additive rather than just the churn. We have terrific inventory. We just did a relook at all the inventory in the basin and kind of divided it between premium and Tier 2, and we feel like we have 25% of the premium core inventory in Appalachia relative to all the other players out there. So we don't need to consolidate for inventory reasons. We're very blocky in our acreage. We control as long laterals as we want to and drill one after the other, sort of mowing the lawn. So that's often one of the key drivers, and that's just not an issue for us. We have plenty of takeaway, as we've talked about. So I don't think we have as many catalysts to want to go out and acquire from our standpoint. But macro-wise, yes, I do think you'll see more. For AM, I think we're always looking at various things for AM. And does AM need to stay in basin? I think AR will stay in basin. AM, not necessarily over time. But right now, there's nothing near term, but AM is always looking as well at ways to create value.

With that, we have reached the end of our session. Glen, Justin and Dan, thanks for your time today. Hope we can do this again in person next year. Everyone, have a good and productive day.

Thanks, Ned, and I think there's a good chance of that. We appreciate it. Enjoyed it. Take care. Thanks, everyone.