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

All right. Good afternoon, everyone. We're here today with Micheal Dunn, EVP and COO of Williams. Before we get started, I just want to remind investors that there are 2 ways of asking questions. You can either type it on the screen, and that will get sent to me or you can just e-mail directly -- e-mail me directly at [email protected] do that at any point during the session. Micheal, I'm going to turn it over to you. I think if you have a few intro remarks, then we can go right into Q&A.

Sure. Great. Good morning or good afternoon, respectively, on wherever you are today. Great to have you here virtually. And hopefully, we can all get together in person next year to do this. But very happy to talk about Williams today and the great year that we're having so far. As you all probably know, we've increased our guidance a couple of times this year. So financially, the business is hitting on all cylinders. But operationally, the team is doing a great job as well. Our reliability has been strong, been dealing with the COVID situation for about 2 years now as we all have. And our team has just really come through it, doing a great job, keeping our customers satisfied and continuing to move our products to our end users. So let's open it up for questions and see what's all on your mind.

Okay. I'll start and ask some questions trickle in. I got a bunch anyway. But I guess the first thing I want to start with is that there's been a lot of volatility here with commodity prices both up and down for gas and NGL. So I'm just wondering if you can give an update in terms of what you're seeing from your producers across your various G&P segments?

Well, I would say, first, I believe we've seen a lot of discipline over the last year, and our producers have been very careful to improve their balance sheets really across the board. And I think this price increase that we've seen this year has been a great opportunity for them to do that. But they're still maintaining a disciplined nature when it comes to planning. I would say we're seeing a little bit more activity and the expectation for increased drilling primarily from the private producers that aren't necessarily fact that they're staying disciplined. But I would say that I'm optimistic that they're going to stay disciplined and we'll continue to see production increases, meeting the demand expectations. We saw with the price increase, a little bit of a demand pullback from the power sector this year, but it was more than offset by volumes going to the LNG facilities as well as the exports to Mexico and our industrial loads were staying very strong throughout the year. And so we watch demand really closely, and we're continuing to see high expectations for demand to continue to increase. I suspect we'll have a winter eventually this year, and we'll be able to see that demand uptick as we move further into the winter region here in the near future. But for the most part, we're pretty optimistic about our systems. We have outperformed the overall industry when it comes to gathering volumes. If you look at how much gathering or production increases have occurred across the country, we're capturing more than our fair share of that when it comes to our increases in our systems. And so that's really the benefit that we have of being spread across significant diverse geography and diverse customers. We have basically exposure to every large producing basin in the United States. Even in the Permian, it's a small exposure, we have exposure there, but really pleased with how our systems have held up and actually increased our market share from a gathering standpoint.

Great. And I guess, as you look at your different regions between the Northeast, Rockies, Haynesville, are there any of those 3 regions that you see more momentum as you head into '22, I guess, how would you rank order those in terms of areas where you could see activity pick up?

Well, I would say that we're seeing activity increases across the board there, especially in the Haynesville and the Northeast. We've had projects that we've been building out on the gathering side for customers in the Northeast, but we're seeing customers starting to leg into their transmission capacity that they've undertaken. For example, our Leidy South project on the Transco system has come in, stair-stepping increases along the way as we brought assets online this year. And we're almost complete with that project. We would expect the last tranche of capacity there, which is about 75,000 dekatherms to come on before the end of the year. So that's 580,000 dekatherms of new capacity that's coming right out of the Northeast Pennsylvania gathering systems and moving on to the Transco system. And so we're seeing that activity obviously continuing to increase, and those capacity stair steps have been filled as we brought them online. And so I would say the Northeast, we'll continue to see some similar activity. Haynesville has been very hot. Pricing has been better than it has been in a very long time for the Haynesville exposed producers. And so you're seeing a lot of activity there on the private side. And we're seeing a lot of interest in expanding our gathering systems and trading systems in the Haynesville. So I would expect we'll be working towards some additional expansions to serve those customers in the Haynesville. And then ultimately, there may be opportunities to build takeaway projects out of the Haynesville to serve the new growing LNG facilities on the Gulf Coast. And then finally, the Rockies, very strong performance there from our existing assets, and we have our JV with Crowheart that we acquired through bankruptcies and a purchase of BP acreage in the Wamsutter where we now combine all that acreage, over 1 million acres of production opportunity there. And we've been working many of those wells over this year. Crowheart had a great plan coming there and with some very economical workovers, and we're continuing to see new production come on for wells that have been shut in from the previous operators. And they're ramping up their expectations for their drilling program for next year as well. We have a very tight window of drilling that we can do in the Wamsutter in Wyoming, just because of the winter and big game restrictions that are in place there. But we'll hit the ground running next summer with getting some additional wells in. But I wouldn't expect to see large growth in production of that area until toward the end of the year in 2022.

Got it. And maybe if I could just touch on a comment that you mentioned in terms of the Haynesville. So if we continue to see kind of production growth there, you mentioned expanding takeaway capacity. What would that look like exactly, would you partner with someone? What assets are you referring to specifically that you could expand?

Well, the benefit that we have in the Haynesville is that the acreage that we acquired from Chesapeake is about 50,000 acres, and it's very good rock in the Haynesville. Our partner, GeoSouthern is actively drilling wells today there. And we have the rights, we are sequenced subsidiary to market all of the gas that comes off that acreage. And so we can apply that to a project, either one that we build ourselves or partner with someone else on to take away that gas out of that area. And we have many other opportunities with our producer customers to work with them to move their capacity to market. And we really started talking about a wellhead-to-water strategy for our business, and that means taking responsibly produced natural gas when we hear a lot about that, RSG, responsibly-sourced gas. We think we have the opportunity to be able to do that with our producer customers, with our transmission business and ultimately get this natural gas either to a local distribution company that values that responsibly source gas or to LNG off-takers, where we can actually tag those production capacities and those production volumes coming from those producers through our systems, track that, trace it and make sure that we're creating the smallest greenhouse gas footprint that we can and then obviously have the benefit of putting that on cargoes to go worldwide markets. And so that's ultimately the strategy that we're working there. There's been a lot of talk about that. And I think it's important for us as an industry to continue to focus on reducing the emissions from our operations as we go forward and Williams has done a great job at that over the years.

Great. I have a question here from an investor who is asking what is the opportunity set for continued pipeline expansion along the East Coast? I know you've announced at least one FID deal and then there's another that you're working on, on Transco. So maybe you could talk about that.

Sure. That's a great question. I'd love to talk about that. We've got some really great opportunities to continue to expand the Transco pipeline system. This is the largest transmission pipeline in the country, and it's been the fastest growing for a number of years now. And our Leidy South project is the latest project that we're putting in service. We have our Regional Energy Access project. It's over 800,000 dekatherms of expansion capacity from the Northeast PA area into markets in New Jersey, New York and Maryland, and we would expect that project to be online so when we achieve all permits in 2023. But we recently announced a couple of Mid-Atlantic projects that we've had successful open seasons on. We have the Commonwealth Energy Connector and the Southeast Reliability Enhancement projects. Those total over 500,000 dekatherms of expansion capacity in the Mid-Atlantic region, so serving North Carolina and Virginia markets. And then we have another project that we just recently concluded an open season on in the Southeast, and that's 150,000 dekatherms at the minimum. We expect we might be able to grow that a little bit larger, but still in the early stages of that one, but another successful open season on the Transco system. The first 2 projects I mentioned, we've already filed for our prefiling with the FERC on those. And those are some long permitting windows there. We're looking at 2024, 2025 time frame for those to go in service, but we are actively working other opportunities along the Transco corridor. And we think it's very advantageous for Transco assets in the corridor that we're in. If you look at that on a map, we serve all of the major metropolitan areas on the East Coast. They are still growing their demand, and there's been a number of projects that have been canceled over the years. And we do think we can come back with some more environmentally friendly projects that build off the brownfield aspect of Transco and continue to grow our volumes coming off that asset. Ultimately, the conclusion in in-service date of the Mountain Valley Pipeline, we believe will drive additional opportunities to market projects off the expansion of Transco. The Mountain Valley pipeline basically dead ends into Transco at Station 165 on Transco, and we ultimately believe we'll be able to build expansion projects off the back of that project on the Transco system, either north or south of Station 165.

Got it. And I guess this is tied to your development of Transco. But longer term, I guess when we get this question a lot, which is that you have all these utilities that are talking about Net Zero and the rise of renewables, but at the same time, they're signing up for additional capacity for expansion. So when you look at your LDC customers and utility customers and they show you their demand forecast for gas as you go out in time. Are any of them actually projecting a decline in gas? Or is it kind of rising or flat? What are they telling you in terms of their outlook?

Well, I think what we're seeing is a continued appetite for natural gas behind their meters. They're seeing growth in their systems. They're seeing continued increased demand for natural gas, either through new home or commercial construction. And then you got the power generation markets as well. There's over 75,000 megawatts of coal-fired generation still in the states we're in Transco's corridor. And virtually all of that is going to convert to some other form of electric power generation at some point in the future. And many of those coal-fired plants are being shut down early. There's been numerous announcements in recent years and in recent weeks about the acceleration of these coal plant shutdowns. And virtually, there's going to be either natural gas or renewables to serve those. And they would say the offshore wind. It's still in its infancy on the East Coast. There's been a lot of discussion and talk and permits for the offshore wind. But they -- the utilities still have an obligation to serve and I have to be incredibly careful about committing too much renewable generation and still having the obligation to meet load demand and load demand continues to grow on the electric side. And we really think we'll have a great opportunity to continue to capture either baseload natural gas-fired generation or back up natural gas generation that backs up the renewal projects that are being built. And either way, that creates capacity development opportunities for us on the Transco system.

Got it. I have another couple of questions here coming in. I think this question is referring to our last webcast that we did where we had Kinder Morgan and they were talking about the need for an additional gas pipeline in the Permian in the 2024 time frame. And so the question here is that an opportunity for you guys, would you consider building a gas pipe in the Permian?

Well, we've looked at building a gas pipeline along the Permian in the past. And some of the contract terms that were being evaluated there, we weren't comfortable with. 10-year contracts is something that we wouldn't say no to, but you really have to be certain that at the end of that 10 years, you're going to have an opportunity to recontract that pipeline because you do count on earning revenue from that much longer than 10 years and we start thinking about terminal values of those assets. And so for us, we don't have a large presence in the Permian from a gathering and processing standpoint, and we might be looking elsewhere for our opportunities. We wouldn't say no to something like that. It's something we've evaluated and certainly, there's opportunities at times to partner with other operators to develop those kinds of projects. But it's not something that we would say no to. We just have to look at the whole gamut of opportunities that we have across our entire system and make a determination if that's where we want to deploy our capital dollars you know. We have a wealth of opportunities elsewhere across our entire system, including the Gulf of Mexico that would probably come well before we would step into the Permian just because of the presence that we have elsewhere with our current assets. And you know our goal is always to be #1 or #2 in an area where we operate. And that's the positions that we like to have. And so that's where we're certainly deploying our capital investments at this time.

Got it. Maybe kind of switching gears a little bit. Can you talk about the benefits of implementing a tracker for modernization CapEx spending on Northwest and Transco. I think you're trying to get that sorted out. And then the maybe if you can update us in terms of how much modernization CapEx has been spent to date for which you're waiting to recoup a return?

Sure. Well, I would say there's several benefits of having a tracker. It certainly gives us certainty on when we're going to actually get the revenue coming in the door for those maintenance capital investments. But it also gives certainty to our customers because in that tracker mechanism, we can basically predict how much of an increase that would occur. And we don't have to go through the trash of having a rate case to ask that out and settle that. So I think there's a benefit for our customers there as well as ourselves. They get certainty. We get some certainty in regard to how soon we're going to get the return back. But if you think about the modernization of capital that we have anticipated spending, it's very similar to our maintenance capital. I mean it's basically, it's deployed either in the process of getting return prior to a rate case. And then you have to obviously get through your rate case process and then increase your rates in order to accomplish a return on that investment we've made in our maintenance capital. And the modernization without a tracker would be very similar. So we would certainly like to have a tracker in place. We've been discussing that with our customers on both Northwest Pipeline and Transco. But short of having a tracker, we'll still go into these modernization projects and go through the normal course process of a rate case to extract a return on that. I would say we're still in the early stages of deploying any modernization type capital. We have one project in the way in Colorado, Northwest Pipeline, compressor station, we're replacing one of those out there because of some chimney regulation, Colorado required an emissions reduction there on the western slope. And we have a station that drove we're anticipating on the Transco system, replacing over the next several years as well. And it really creates a lot of benefit for our customers from an airship standpoint. I mean they're doing the same thing in their locals, but they're trying to reduce their emissions profile. And this gives us an opportunity to do the same thing. There's a human health emissions impact there from the NOx emissions from our units where we can go in and replace it with state-of-the-art equipment, whether it be natural gas-fired turbines or electric driven equipment. There's a substantial reduction in NOx emissions, which creates Ozone, which could be a human health concern. And then we have methane emissions reductions as well with the vintage stations that we have there. We've got a lot of work to reduce our emissions footprint there over time, but they still have a lot of methane slip, natural gas through the reciprocating process, which we can virtually eliminate the replacement of that equipment.

I guess that leads into the next question here, which is, is there anything in the Build Back Better bill that's meaningful, positive or negative for Williams. I know there's some talk about methane, regulating methane emissions, fines on certain levels of methane emissions and also fees on offshore oil and gas pipeline. So is there anything there that's kind of needle moving for you guys?

Well, I would say the socket making is still underway in that still back better, but we do have teams that have some insight into that. I would say from a methane emission standpoint, we feel very comfortable about where we stand today. We've been undertaking methane emissions projects for a number of years here at Williams. We were some of the first industry players that went out and started reducing our blowdowns on our pipelines where we were decompressing from one pipeline into another when we were doing maintenance on those projects. It was not required by the regulations. It costs more, took longer to do the projects, but it was certainly the right thing to do for the environment as well as our customers because our customers were obligated to replace that natural gas in the pipeline system through their rates. And so we've been doing that for dozens of years now on our systems where we have the capability to do that. So if you look at our commitment that we made to the ONE Future Coalition a number of years ago, we're about 8x better than that 2025 commitment that all of the participants made to the ONE Future Coalition. So very proud of our accomplishments. We've been able to make today from an emissions -- methane emissions reduction standpoint. So we feel very confident that we'll be in good shape with whatever if there is any kind of methane emissions requirement in the Build Back Better plan. I've heard some discussions and talk about some charges that would be in place for offshore pipelines. And I would say it's really early in the infancy of that discussion. I'm not sure that, that will survive ultimately, but we feel very confident we'll be able to recover those costs in one form or fashion or another if anything like that gets enacted into the legislation.

Got it. Kind of switching around here. Can you discuss your long-term strategy for adding more renewable natural gas to your portfolio? And I guess, tied to that, have you considered investing more upstream into the actual processing? And if yes, can you do that organically? Or do you have to do M&A to kind of acquire the expertise to be there?

Yes. So today, we have, I believe it's 7 connections to renewable natural gas facilities, whether they'd be dairies or landfills. And those have been developed by third parties that have come to us and ask for a connection to our system. So that's really the strategy we've undertaken thus far is being able to connect those facilities into a system to facilitate that renewable natural gas into our system. I think we're bringing in about 13,000 or 14,000 dekatherms a day. So it's not huge volumes, but it actually is reducing methane emissions in the environment to looking at our part there. And we've not yet ventured into any upstream investments, if you will, being the actual entity that fills these collection systems in the landfills or in the dairies. But it don't mean we wouldn't do that. We've been evaluating many of those. But that's a different risk profile. And you have to make sure that the certainty of the credits are there because that's where the bulk of the value comes from. It doesn't come from the selling of the methane or the natural gas that comes off those assets. It's really from the credits that you achieved there. And for us, we've not taken that step yet, but it doesn't mean we wouldn't. We are evaluating many of those either as a developer or partnering with a developer on those investments. But I don't think that you'd have to do that through M&A certainly, there's plenty of opportunities out there to work with developers and they certainly would entertain having partners to do that.

Got it. I guess staying on the ESG theme here. So it's clear that building a gas pipe into certain states in the Northeast is very challenging. But is there any opportunity from your perspective to try to underwrite either a hydrogen pipeline or an RNG pipeline to get into states like New York? Is that something that they will be open to and some that you would consider?

Well, we certainly are open to it. We have a new Energy Ventures group that's evaluating that great thing. Our Regional Energy Access project, we actually are working with one of our customers in New Jersey about developing hydrogen production, utilizing renewable energy and then injecting that ultimately into the Transco system on their behalf. And so we are open to that. We're evaluating doing that and working with customers today to be able to put pilot projects in place to accomplish that as we speak. So we're very comfortable with that. Certainly, we all have to evaluate the safety aspect of that. There's been a lot of discussion about how much hydrogen can you actually put into the line. But even if you're thinking about 10% hydrogen blended into natural gas, that's still a huge amount of hydrogen, and we're on ways from being there today. And so we've been -- the industry was limited to 10%, that would be a substantial amount of hydrogen introduced into the systems today.

That feeds into the next question here, which is maybe if you could provide an overview of your MoU with Ørsted and how large of an opportunity that could be? And what would the returns in contracting looks like hypothetically?

Well, it's early to predict returns, but I think it would certainly compete with anything that we do in our normal natural gas gathering and processing or transmission business. But really, what we're looking to do with Ørsted is bringing in an expert in renewable energy as well as hydrogen to help us further our efforts in that regard. And primarily, we're looking at that with them in Wyoming today. We have a grant that we received from the state of Wyoming and we're also working with the University of Wyoming in evaluating using Wyoming as a hydrogen hub. And we have substantial operations already in Wyoming. We have a large acreage position in Wyoming that we now own. We own over 200,000 surface acres in Wyoming. Through our acquisition on the Southland parcels through bankruptcy last year. And so we not only own the minerals, but we also own the acreage. And that acreage can be used for development of renewable energy. For example, you could put wind out there if it's a reasonable area to develop wind resources or you could use solar resources there as well. And then you could use that offtake from that renewable energy to create hydrogen. And that's what we're evaluating today with Ørsted. So we're early in that, but we certainly are looking to partner with experts like Ørsted that certainly supplement our workforce and our expertise in these areas and very happy to have them on board.

Got it. Maybe touching on capital allocation here. Maybe if you could provide more details on your approach to buybacks. I know you've got a formula, but maybe some more clarity in terms of with where stock prices are today, how does buybacks compared to dividend growth and continued debt pay down?

Well, I would start by saying that we have a great runway to generation of free cash flow in our business in the coming years, and it creates great opportunities for us. We've been very diligent in improving our balance sheet, getting ourselves to BBB credit across the board and certainly exceeding our goal of having a 4.2 debt-to-EBITDA metric in place as of last reporting period, when we reported earnings, we were at the 4.0 level and so really blue past our 4.2 goal. That gives us a lot of opportunity to do different things with the free cash flow continue to generate. It gives us an opportunity to continue to deleverage, if that's where we want to go. And as we all know, we created a share buyback program that was authorized by our Board. And we were somewhat creative in how we determined as to when we would buy back stock. And basically, there is a differential between the yield on our 10-year debt and the dividend yield on our stock. And when we hit that criteria, that's at the point where we would buy back our stock. So there's 2 ways you basically can widen that spread, you can continue to deleverage and drive down the cost of your 10-year debt, the yield on your 10-year debt or the price is down of our stock. And certainly, we don't like the latter. We would love to obviously keep the price of our stock high and keep that going higher. And -- but if there is a dislocation in our stock price, we have the opportunity to see that yield spread widen and then we would take advantage of that and buy back shares. And if you back cast the strategy that we've developed, there would have been times in the last 2 years where we would have repurchased our shares. So it's not unforeseeable that we would do that. But we thought it was prudent for us to put some mechanism in place so that we are prudently buying back our shares. And we have to evaluate the best way to deploy that excess free cash flow. And that doesn't mean that strategy couldn't be changed by the Board at some point in the future, but that's the strategy that we put in place today for the buyback of our shares. So we have the program on the shelf and it's available and ready to go. That spread comes to the point where it hits our trigger.

Got it. And I wanted to touch on asset sales. I know in the past, you talked about potentially monetizing some of your gathering and processing assets. You also have some upstream assets that you picked up from Chesapeake. What are your latest thoughts with respect to those assets?

So yes, we have looked at -- it was in the late stages of 2019, early 2020 prior to the pandemic, where we were evaluating the possible sale of a portion of our West G&P assets. And we were doing that in order to improve our balance sheet, basically, we were looking at how could we accelerate the improvement in our balance sheet. We had very strong free cash flow off those West assets. And at the time, we had a lot of interest in that. And about the time we were going through that process and that evaluation, the pandemic was upon us. And so that pulled back, obviously, a lot of investor appetite for that. And so we put that on the shelf and said, what why don't we just go operate our business well. And fortunately, we saw a very strong performance through 2020 during the pandemic and continuing on into 2021. So where we got our balance sheet where we wanted it to be. In fact, we passed where we had hoped to achieve. And so there's really no need now to go out and sell a portion of our West G&P assets. So as I said earlier, it generates great free cash flow. It doesn't take a lot of maintenance CapEx to continue to operate those assets. And so we like the free cash flow generation we get from those assets. As far as the upstream goes, we've been very clear that we aren't going to be a long-term owner of the upstream assets that we were able to acquire through these 2 bankruptcy processes and through the advantageous purchase of BP's acreage in conjunction with the Southland acreage in Wyoming, Really, the goal in Wyoming was to put all of that checkerboard acreage together into one agreement and make it very opportunistic sale at some point in the future. And so now we have all of that acreage locked up in one agreement, and it's not checkerboard anymore. So if somebody wants to come in there and evaluate drilling very long laterals, they can do that today with one agreement and with one operator. And so I would hope that in the future, once we get this development off the ground and continue to show that this is a very viable prospect, we'll have a lot of interest in the sale of that upstream acreage. But the goal really is to get it developed, get it off the ground and drive business through our midstream assets that we have there sitting today with really not a lot of capital investment to make on midstream side of the business there. A very similar story in the Haynesville, where we acquired the 50,000 acres through negotiation with Chesapeake in the -- on the bankruptcy process they were going through. We've now partnered with GeoSouthern in the Haynesville, and we're drilling a couple of wells there today as we speak. And they have the opportunity to leg in to ownership increases as they provide a disproportionate amount of the capital that it takes to develop that acreage down there. And as they do, it will diminish our ownership interest over time as they continue to invest on the upstream drilling prospects on that acreage. And so I would expect to see them very aggressive down there, developing that acreage and create opportunities for us to then go market that natural gas that comes off that production further on downstream.

Great. I think in the interest of time, we will end there. So Micheal, thank you so much for participating in the conference and happy holidays.

Great. Thanks for your time doing. Good to see you.

Bye.