The Williams Companies, Inc. (WMB) Earnings Call Transcript & Summary

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Okay. Good afternoon, and thanks, everyone, for sticking around this long to the final presentation of the day. We've saved the best for last here. Pleased to be joined by John Chandler, who is the SVP and CFO of Williams. I think we may also have Danilo Juvane, who's the VP of Investor Relations. Before we start, just a quick reminder. If you want to ask a question, there's 2 ways to do it. You can either raise your hand in Zoom, click that button, or e-mail me at [email protected], and I'll ask on your behalf. But in the meantime, I've got a bunch of questions prepared. So John, maybe we can just jump into Q&A, if that works for you.

That sounds great.

Okay. Great. So I'll start with the recent announcement on the global resolution agreement with Chesapeake. Maybe if you can just provide some background to that and also quantify how much rates were reduced in the Haynesville and what you bought back for that in exchange?

Yes, thanks for that question. As long as I've been here, there's been a lot of questions around Chesapeake. And Chesapeake has been obviously fighting their leverage situation for several years and that -- that in of itself has consequences for us as a company, just given the fact that they were capital constrained, and that's never good for your producer to have that -- be in that kind of situation. But more broadly for us, I think there was a concern about Chesapeake's impact of the bankruptcy on us. All along, we've said that, to the extent -- and this is across the board, to the extent you're connected to the wellhead and to the extent you have a substantial system, it gives you a lot of power or a significant standard and payable relative to your agreements in the case of a bankruptcy. A lot of people heard that, but I think wanted to see that play out. So we're -- that's the good news around this resolution is that demonstrates that in [indiscernible]. And so if you think about the resolution that we have with Chesapeake, of course, it's still subject to the bankruptcy court approval, which we hope will happen here in very short order. But as it relates to that resolution, in the Eagle Ford, we have wellhead connectivity there, very substantial system. We had a cost of service agreement with Chesapeake that we converted to an MVC last year, a very sizable MVC payment that we're receiving from Chesapeake, and we had a rate increase. And so -- but Chesapeake has agreed that they're not rejecting that contract. They really can't. I mean it's a substantial system, again, connected to wellhead. It will take a very long period of time to [ spud and ] replicate the system and build the new system after reserves have already been produced somewhat out of the basin, just -- it'd be hard for somebody to see what their rates do. So that's good news. So they will continue along with their contract and their MVC and their rates, as already agreed to. And of course, it'll pay us for all [indiscernible] receivable. So we'll be brought [indiscernible] fairly soon on that. Not clear if that will happen here in the next week or 2 or it will happen right at the beginning of next year. It's kind of subject to board approval or the court approval of our agreement. As it relates to the Bradford Supply Hub, we've said there, too, it's great acreage that Chesapeake owns. The cost of service agreement, they've been very successful in drilling that acreage and the rates, as a result, are low there. And we didn't think anything would happen there and nothing had, as we're continuing on there. Although we do hope and expect that you may see some more activity from Chesapeake in the Bradford Supply Hub now that they're better capitalized. And so finally, it brings us to the Haynesville. It's the only place where we really did change an agreement. And in the Haynesville, we had already offered Chesapeake as well as a number of the other producers in the basin incentive rates relative to our base rate to develop new acreage and bring new production to the system. Our base rate was higher than the market, we knew that. And so we've already been offering those incentive rates. The only thing we hadn't done is reduce our rates relative to the PDP production owned by Chesapeake. And so as part of this resolution, Chesapeake asked us to lower that rate. And so they could permit more activity to that market, if we would do that, more drilling activity. And so we ran that analysis and concluded that in lowering our rates. We believe there would be enough drilling actually to offset that. So we'd be NPV neutral, even just from the exchange of the rate for the new drilling, although we were not willing to take that bet just on its face. So we did seek other sources of NPV. And so as a result of this resolution, Chesapeake did give us about 50,000 acres in the Southland field area, so to the southern part of our Haynesville system. There's existing production there today, about 130 producing wellbores there. So they're suggesting PDP production there today, and there's certainly a lot of acreage that could be developed. There's a lot of producers down in that area, smaller producers that are developing acreage. It gives us the right and the ability to actually determine who's going to own this acreage long term. We're not going to be in the business of owning the upstream acreage. That's not what we want, but we do want to control who's drilling that, and it will give us a nice NPV uplift. And so likely the structure that unfolded in the Southland field area will be some kind of partnership with a drilling partner. They will disproportionately pay for development capital. And over time, they will eventually own the acreage or own a significant percentage of the acreage, and we'll walk away from the acreage, but still receive all the midstream value. So when the dust all settles, at a minimum, we see this as an NPV neutral deal for us. But the reality is, if the development can occur the way we think it can, it would be very, very attractive to us. So we're on [indiscernible] development activity. So again, when the dust all settles, I think the market side breathes a sigh of relief and in fact, it played out like we said it was that now we could hold our ground relative to our agreements with Chesapeake. I think a lot of people are asking us what kind of rate concession we have to agree to? And I will tell you, our rates in Haynesville in the mid 50% per Mcf range and market rates were about 40% less than that. So we did -- on existing PDP production, we brought our rates down by about 40%. When the dust all settles, as we think about our EBITDA generation next year, there may be a slight dip in EBITDA in the Haynesville. We expect additional production, but at a lower rate, we may see a slight dip. By 2022, we expect that to pick back up, and we'll see better EBITDA.

Okay. That's very helpful. That makes sense. I guess maybe if you could turn to -- just your overall G&P operations, what are you seeing from producers? Just a quick overview on the latest developments there? And then maybe any preliminary commentary you could provide in terms of volume expectations heading into '21?

Sure. First of all, on our earnings call in the third quarter, we did say that we expected to see EBITDA growth into 2021 -- off of 2020. And we still see that and still believe that we're going to see that going into 2021. As we look at our basins that we operate in, of course, with the Permian associated gas kind of fallen off as production has fallen off there, that certainly strengthened our Haynesville position and strengthened the Northeast. That's the good news. The bad news is we've got some well-capitalized producers who say, I don't like price, and I'm not going to produce them without more significant price curve. So Taggart, for example, is continuing to say they're going to operate in maintenance mode. And as a result, we would expect Susquehanna in the Northeast to be generally flat from a volume standpoint. Chesapeake operating the Bradford, we expect to see a little bit of a volume uptick there, but they pay a pretty low rate. So I wouldn't transpire that into significant EBITDA uplift, but a little bit of EBITDA uplift from the Bradford Supply Hub. Southwestern, as said, I think in our earnings calls, they need to see a more sustainable long-term gas price as well. And so they may operate in a maintenance mode in kind of Marcellus. However, I would say they are very active drilling, and they've seen significant volume growth this year. And so when they talk about maintenance, I think they're talking about exit rate from a volume standpoint. So what that means for us? We do expect to see a little bit of growth in volumes around the Marcellus supply hub. More importantly, that's liquid-rich volume, and we've invested a lot in our processing capabilities and some of our NGL infrastructure in the area. So we do expect to see some EBITDA growth from additional processing volumes at our facilities. So -- and then finally, I'd say, around Laurel Mountain Midstream, Chevron hasn't been actively drilling that over the last year, while we've been in the sales process, [ EPP ]. It looks like we'll be the acquirer of that property. And of course, I think they would eventually start developing that again when they feel like prices stabilize. In the meantime, volumes will fall off a little bit there, but it's subject to MVC. So from an EBITDA standpoint, we expected -- anyway, when you put all that together, we expect slight volume growth in the Northeast, nothing substantial, but we do see a slight volume growth in the Northeast. In the West, we -- again, we expect to see some volume growth out of the Haynesville, but it will be at a lower rate, so a large portion from an EBITDA standpoint. The Barnett, we may see a little bit of growth out of the Barnett. In the Eagle Ford, while volumes could be flat to down a little bit since there wasn't a lot of drilling activity from Chesapeake this year, but it really doesn't matter to us from an EBITDA standpoint to say this was expected by MVC. So as we look to the West, in aggregate of all of our basins, we expect kind of flat to maybe slight growth in the West as well. And maybe -- that doesn't mean our EBITDA will grow over there. There's a whole different agreement we have on Overland Pass Pipeline. This could be a little bit step-down on our Overland Pass Pipeline system. So the West may be down a little bit from an EBITDA. Northeast is going to be up a little bit from an EBITDA standpoint. Our transmission systems will be up a little bit just from new pipeline projects brought into service and we don't have the hurricane season like we had this year.

Okay. That's very helpful. And then if I could just tie that into just total EBITDA, which you expect to be modestly up in '21, is there anything else that we should factor in here when you're looking at '21 versus '20?

No. I think, again, just some big things to think about. The hurricane activity had about $40 million inflow. Hurricane and COVID and oil price shock and some of the producers in the deepwater Gulf shut down for a short period of time. So when we aggregate the impact of that shutdowns [indiscernible] all that volumes return and the hurricane activity, it had about a negative $40 million impact towards 2020. We're not counting on that to happen again. So we should see an uplift of $40 million from that. Offsetting that, we've had a tremendous year from a cost savings standpoint. And we started this back in -- actually, 2019, we are very focused as a company on operating margin percentage, which is the amount of EBITDA divided by our gross margin. And we look at that by franchise by franchise, and we insist with our management, but we can't let that go backwards. And so we saw that going backwards in 2019, because we thought gas prices were going to be low, we saw some lower revenues coming. And so we jumped into action and cut $75 million of salary wages out of our business in 2019. So that was already done by the time we got to the end of 2019. And we did that through a voluntary severance program and reductions in force. So while a lot of people are talking about cost reductions this year, we already did that. In addition, obviously, COVID created cost savings, not nearly as much travel occurring within our company. And there were some also -- some maintenance issues, where sometimes it's just hard to get crews in the field due to the travel restrictions even service providers are experiencing. So as we look to a total year, I think our cost savings could be in the tune of $110 million to $125 million, sort of in that range, 2020 over 2019. And that, by the way, also includes after a pretty good uptick in operating taxes. So that's even net of an increase in operating tax. So we've done a great job in cost reduction. We think of that increase, I'm talking about, or decrease in cost to $110 million to $125 million, at least 2/3 of that was there, but there could be 1/3 of that coming back our way. Just again, it's COVID related, timing related. How much of that comes back is going to be a function of how long are we going to continue to be in this environment [indiscernible] things like that. So I guess I say all that to say, good news, the deepwater Gulf of Mexico should pop up from the lack of hurricane activity. Bad news is we still -- our overall costs are down, but we could see a rebound of some of those costs that would offset that. And overall, the growth in the Northeast and the growth will offset -- the growth in the Northeast, some of the growth on the transmission systems will be more than offsetting [ obviously ] in the West.

Okay. That's very helpful. We've seen G&P valuations improve over the last few weeks. I know in the past, you've been looking to sell your West G&P assets. Where does that stand today? And do you think we can actually see a transaction next year?

That's -- it's hard to know exactly when we see a transaction. I can tell you we're still interested. If there was an opportunity to do something like that, we would entertain that. But -- so there's some pluses and minus -- some good things that happened. When we were talking about selling an interest in our gathering systems in the West last year, we were having -- we were fairly far down the path of having conversations with a number of private investors -- private equity investors, who've had interest in that. They had a lot of the same questions that a lot of investors have about, what might the cash flows look like with Chesapeake bankruptcy filing, what about a tough commodity environment, how does all that shake out? We still have got a lot of interest actually even with those concerns. So the good news is, relative to where we were at the beginning of the year, I think there's a lot of questions that have been answered relative to that, which I think add to confidence by those investors. That's the good news. Another thing that happened, obviously, the high-yield market disappeared there for a long period of time. It's kind of starting to resurface. I mean not as much for energy, but it's starting to resurface. And so any investor in a joint venture with us probably was going to back leverage their investment, we wouldn't want an investment to occur at the joint venture level or debt, but obviously, they would have counted on back leverage. So that market's got to improve, in my mind, still or actually want to see a transaction that we would find attractive. And the final thing I'd say. I think coming out of this environment, there are some single basin, single producer midstream systems that struggled here. And I think there's probably going to be some opportunities over the next 6 to 9 months. And the question is, do you want to be selling an interest when there's distressed assets in the market and the answer is probably know. We've got a quality system with quality cash flows. And so we'll have to see how all that shakes out. The good news is we're migrating towards our leverage target of 4.2. We think we'll be getting in the ZIP code at the end of 2021 and certainly into 2022, we'll get there. And so we don't have that kind of thing driving us. But I think, again, coming out of this environment that we've been in and how our EBITDA is held in there, I think it should create a lot of confidence. And for what it's worth, a lot of people don't appreciate this, but our gathering systems in the West are massive free cash flow generation machines. There's not a lot of reinvestment in well connects. So we already have substantial systems connected to a lot of wells. And so there's a lot of EBITDA with not a lot of capital. And so that's what really attracts us investors reach free cash flow generation coming out of this as well. So really, bottom line is we'll stay in tune with that market. And who knows, maybe an opportunity emerge, I don't see there anything coming in the near term, but we're still interested. We're still talking to people. And the conversations have twisted a little bit now more towards, would we entertain operating a system that maybe a private investor might be interested and acquired? And so those are interesting things for us to evaluate and our desires there would be to create synergy value for existing assets, if we could. And so we'll be looking at those probably more so in the interim to see if anything makes sense on that front.

You covered a lot of topics there. So I'll dig into some of it. So in terms of the -- your leverage and getting to your target sounds like in either '21 or '22. Once you get there, you may get this question asked a lot, but how do you rank buybacks versus dividend growth? And also in the context of the recent improvement in stock prices, has that changed your desire to do buybacks at all?

Well, no. I would say and there's a lot of sub points to that question. First and foremost, we see a lot of value in getting our leverage right. And we think we get a lot of questions from investors about terminal value. And I think embedded in terminal value is ESG question, is natural gas a long-term fuel? We think absolutely in any -- even the most aggressive renewable analyst acknowledges that gas has to be part of the solution even over the long run. So that's part of the answer. And part of the answer is having your leverage right, too. So now, we targeted 4.2 as the right leverage metric, and we believe that's where we needed to get to be solid BBB with S&P, Moody's and then Fitch. S&P and Moody's -- S&P and Fitch already have us there. We're having conversations with Moody's. We think we've done a lot to improve our stability of our cash flows this last year. And so we hope they acknowledge what the other agencies are to acknowledge. And so what that says is 4.2 or even something slightly higher than 4.2 qualifies for BBB investment-grade status. And that's what we want. We want people to have confidence. Now the question -- the unfortunate alternative part of that answer is, we need new generalist investors investing in the energy space. Today, you see a lot of cycling of capital, we'll trade up and Morgan [indiscernible] Magellan, you name it, trade down, and then another day, we trade down and they trade up. And I think it's just money moving around baskets. And we've got to break out of that cycle. And so we've got to bring generalist investors in. In that world, we're hearing from some that 4.2 seems high relative to the broader industry -- investable industry. And so once we get to 4.2, I think we need to evaluate our -- do we have traction with our investors? Do we see a solid price that's supported? If not, if we believe we could bring in additional investment by bringing leverage down further, we'll do that. If we do think we're where we need to be, then from a leverage standpoint -- or we believe that taking it down further isn't going to really attracting investors. And I think share buybacks are front and center, and [indiscernible] And it's just hard to know. We feel like we should trade back utility today. I think we would debate our cash flows to have a shown -- maybe even more stability than utilities EBITDA over the last several years. And our leverages last and our yield is higher. And so we hope to attract those investors and drive our share price by the time we get to the end of next year. And if that does happen, and again, obviously, I think we see value on our side. The other thing I'd say, too, though is we'd have to evaluate us when we get here. There's a lot of projects that we don't do today. And I would just say use Transco as an example. Transco has significant capacity under its rate base for us to invest in replacing facilities and just modernizing the whole system. We choose not to do those today because they don't stand up to deleveraging, number one, and just our other capital approval projects that we look at. And if you think about the rate base, the returns embedded in those kind of projects, it's never really clear in a rate case on what the agreed-to rate was, but I think the people will be probably in at 12% to 13% range. So that's -- that's the equity piece of the rate settlement and the debt piece is 5% to 6%. You're looking at blended returns on those kind of investments in the 10% range or 11%. Not bad when you think about they're back by utilities, A rated credit utilities. And it certainly relates to additional EBITDA growth for us. So that's certainly another thing, I think, we'd look at -- so I gave you a lot of words and not a straight answer, and I think it's just going to be a function of where with you share price when we get there and whether or not we're bringing those investors in -- new investors [indiscernible].

There's a lot in there. So I guess in the context of that, you are making investments into solar, converting your compressors to solar, how do the economics there stack up to paying down debt, deleveraging, buybacks? Yes, I mean, does that stack up to the 10% -- higher than the 10% rate that you quoted?

Yes, they do. They do. Those investments that we're making match up with our midstream investments we make otherwise. And it's because we're serving [ own mode ]. The investments we're talking about on the solar aren't becoming a solar developer, putting in solar around other company's assets. It's really about looking for where we have electric-driven compression today. And we burn a significant power load in those markets and what it will cost us to build solar and to plant that electricity that's serving those electric compression today. So the projects we've identified are around those facilities, and they absolutely must stand out relative to our mix and returns to do it. We've talked about [ Areco ] $200 million of investment opportunities to support our [indiscernible] electrified compression. And so we put a team together to pursue that. Now that doesn't mean that it doesn't make sense to bring people that can take advantage of the tax credits that are back in solar and other sources of energy. We can't take advantage of that, unfortunately, today. We're a noncash taxpayer for several years. So we've looked to somebody that could partner with us. And of course, that bring our capital costs down pretty significantly, if we had this part [indiscernible] from participating. Today, the projects that we're looking at stand total [indiscernible] with our midstream investments.

And so it does sound like buybacks are still very much front and center when you can get to the point that you do them. Is -- do you envision doing buybacks on an opportunistic basis or setting kind of a programmatic formula-based on your free cash flow?

I hate to even speculate on that. We've not -- again, we're laser-focused on deleveraging our assets in the last few years. And we have had some conversations about share buying back to the Board, but it's never advanced to the point of talking about what kind of program we put in place. And I think that actually gets on the Board on that.

Okay. Fair enough. We've got some questions that are coming in. One of them is, you're seeing various states utilities make decarbonization pledges hitting net 0 by X date. How does that impact the volumes on Transco over the long term?

I think of -- think of this in these terms. A lot of the utilities that are doing that are doing it: A, they could be doing it by moving those -- emissions reductions is really what those utilities are after and in part, doing that by switching to -- switching off coal-fired generation to gas generation. That's one way that they're hitting net 0 type emissions targets. Also, to the extent they invest in solar or wind generation, the reality is until battery technology is sufficient, they have to have backup capacity with peaking plants to be able to supply power to the markets when the sun is not shining and the wind is not blowing. And it makes no sense to have a peaking plant when you don't have capacity on Transco. And so we -- it's just -- I think it's important for investors to understand, we don't make money by volumes that ship on Transco. We sell firm capacity. And we don't see that going away. Utilities have to have firm capacity to backup their backup plans for renewable power, and I don't see that changing for the foreseeable future.

So you've kind of shifted -- if you kind of put all this together, you kind of shifted into this lower EBITDA growth mode, it's understandable given the environment. But I'm wondering, are there any larger potential initiatives that you're looking at, that could kind of accelerate growth or is this just kind of the new norm, generated a lot of free cash flow, send it back to shareholders?

Yes. Well, first of all, I'd say, we really haven't shifted to a lower mode. I mean I guess it's injected upon us as a company. In part, that's driven by a few things. Generally, we have 2 or 3 major pipeline projects going at a time, we had at least historically had that going. And we were hopeful that we would have the Northeast Supply Enhancement project we'd be working on now to supply New York and that did -- that helped really, but that would be a project we would have been working on would add nice EBITDA uplift probably at the end of '21. And so we don't have that in front of us. In the meantime, though, we've got some other great projects on the horizon. We've got Leidy South that will come into service late next -- in late '21. We're working on a project called Regional Energy Access. This is a project that serves kind of the Northeast area. And we think from a permitting standpoint, get that done reasonably well. And so -- and then we've got a number of other -- the ACP pipeline, the [ demanded ] ACP pipeline. We already serve North Carolina and South Carolina, and there was real demand backing that pipe and certainly makes sense for us to step in a void. And we think there's a number of projects we can do to take advantage of that demand. And of course, there's a lot of power [indiscernible] in the Southeast, is still on hold. And of course, LNG exports are starting to pick back up again. And on top of all that, I would say this, you've had a weak gas price for the last 1.5 years. And you had globally a warm winter, not just in the U.S., had it across the world. And so LNG was kind of weak here for the better part of this year. And that will probably continue into next year a little bit, but I think the prognosis is that with a more normal winter, you're going to see gas demand really picks back up. And therefore, I think long story short, I think we see growth returning -- more healthy growth returning for our transmission systems when you get beyond '21. Deepwater is coming on, and we expect a pretty significant increase in EBITDA in the '24 to '25 time frame in the deepwater Gulf of Mexico. And then around our gathering systems, we're in the best basins for natural gas in the lowest cost basins, some of the best producers. And so with a more normal winter and a return of LNG exports, I think we expect to see more robust growth coming out of there. This -- again, I'd say we haven't really shifted our focus. It's kind of been shifted on us. And I think we see -- number one, good news is, in spite of all that, we see some growth in EBITDA next year and beyond that -- and we're free cash flow -- we expect we will probably be free cash flow positive. And then beyond that, we see kind of a better growth coming back our way [indiscernible]. So we feel good about how things were backing up for us.

No, that makes sense. And then just on regional energy access, I think Chesapeake, part of the settlement, it seems like they made some commitments on this project as well. Does that bring it closer to FID at this point? Do you have what you need?

It does. Yes, we're getting close to having what we need. We are trying to build commercial demand for the system. We've got a pretty good book of business behind that. Certainly, the Chesapeake commitment helps on that front. Obviously, lingering out there, too, is the Penn East project. I think to the extent, that feels like that's not going to happen. There could be opportunities there. We'll have to see like that. I would say we're getting a lot closer with Chesapeake.

Okay. And then last question because we're getting short on time here. You've laid out some fairly ambitious plans as it relates to renewables, at least from a midstream perspective, one of the first to do so. To get to those targets, do you need to hire more people? Do you need to enter into JVs to get expertise or make acquisitions of renewable companies? How do you get from Point A to Point B?

Well, interesting enough, we started -- our missions target started with the Paris Climate time frame, which is mid-2000s. And so we've already -- number one, we intended on setting a target. And a lot of people are setting 2050 targets and those targets, they won't be around to see that. And we thought that's not serious in our opinion. And while we have a 2050 target of net 0, we have a 2030 target, which holds us all accountable, but we're at 40% already. We want to be at 56% reduction of emissions by 2030. We're already at 40%. And we've done that through a number of things. We've sold some businesses that have higher emissions related to them. We have changed our procedures on how we evacuate the pipe when we're doing maintenance. We've put in cameras to look for methane leaks on our system. I think we're probably one of most advanced people doing that. And so it's more of that as we go forward of continuing to tighten up our primary containment, our leads, our maintenance efforts, the blowdowns that we'll do in the pipeline. And yes, in the future, I'm sure we will be making -- hydrogen will be part of that answer too, to the extent we invest in hydrogen blending along our systems. We're connecting renewable natural gas along our systems, and we have 6 facilities connected today. And of course, solar is part of that as well. Again, we've kind of taken the first step there with our solar power compression. So it's an all above thing. It's investments on our systems. It's replacing compression on our existing system, even the gas-fired compression with -- we're working with our shippers on Transco to invest on -- along our system to enhance our mission. So it's all the above. But the good news is, I'd say, we've already made significant progress. And we just do a linear kind of calculation, that 56% reduction is what it takes to get to net 0 by 2015. So we'll be well on our way.

Great. Well, we have a lot more questions, but not enough time. So I want to be respectful for your time. This has been great. Thank you for participating. And hopefully, we can all get vaccinated and meet in person next year in New York.

Very good. Thanks. [ I hope you stay safe ].

Take care. Bye.