ONEOK, Inc. (OKE) Earnings Call Transcript & Summary

I am doing this both in person and an audio webcast, and I got to be very blunt, I've been surprised at the amount of inbound e-mails I've gotten both last night and this morning from folks who are actually tuned in remotely to this. I guess we're still in a very evolving world when it comes to in-person versus web space. I want to thank the ONEOK team for coming up. I don't think I do a good enough job of thanking [ each team member ] and so I want to try and rectify that a little bit. And whether it's Pierce, Walter, Kevin, Andrew, all of you all, thank you for taking the time out of your lives and taking the time to come up. For those who are in the introductory session a few minutes ago, you probably heard mine, I'm Michael Lapides. I lead our energy infrastructure equity research team here at Goldman. I'm here with John Mackay and the ONEOK team. And -- you know what, we're going to literally just do this a little bit informally Q&A. And John and I will kind of moderate with you all, and we'll kind of go from there. And look Pierce, I'm going to start with a really high-level one with you, which is you're back at ONEOK. Welcome back.

Thank you. Thanks for the invitation to come to the conference.

Glad to have you. We even focused on? Like you're back as CEO and after a number of years, running a gas utility, what have you been focused on? How is it different from when you left -- and when I say how is it different? I don't mean just ONEOK. I mean how do you think about how the industry is different, kind of touch on all of those.

Well, first of all, I did spend a little bit of time with the utility, about 7 years. I think the most -- 2 things came out of that. One is, I got a better understanding of the customer base, of what goes on behind the city gate because prior to that, I really didn't necessarily have that much knowledge of that. So that's one thing I think that I learned a lot about is the behaviors and what drives that business, those kind of things. Second thing is, I don't think anybody really knows what is like could be a CEO until you actually sit in the seat. So although that was a different industry, there's some similarities between leadership at that level and leadership with another company. So the one thing I learned, and the reason I'm saying is because it helped me focus on what we actually did right after I got back to the company, which is to kind of revisit what our mission, vision and values were. Those are, in my opinion, extremely important because that gives the organization the why you get out of bed in the morning. We knew what we did? How we do it is actually anchored to our values. That's the way we make our decisions. So that was our first focus is to revisit that with this team. We didn't hire any consultants. It was all in-house. So it's what it is that we really felt like would drive the business going forward. So that was our first level of focus. The next thing is you look to see as the organization aligned with that mission vision and values. We've made a few tweaks there. We've made a few hires in between, so we come up to where we are today. The biggest thing I see as a difference between when I left back in 2014 versus today, and this is more an industry comment, is the behaviors of the producers. If you go back in time in 2014, if you would have seen a run-up in prices to over $100, you would see this massive -- everybody runs the other side of the ship to add rigs. That has not happened. So they show a lot more discipline today, which actually is very good for a midstream company. It was very difficult 10 years ago to really plan and to get enough ahead of the -- without putting much risk in the company. And today, because of supply chain issues and long lead times on equipment, if the pace were way faster than it is today, it will be problematic for the midstream companies. So the discipline that the producers show is actually a good thing because it moderates the pace in which we had to perform and stay ahead and make sure that we move the product. So I think that's the biggest difference I see is just the discipline that the producers show.

What's the biggest difference in ONEOK itself? Like when you look internally and you talked a little bit about that, whether it's in the planning process, whether it's in how you look at markets, how you look at -- like now that you're back as CEO and you talked a little bit about kind of the mission, vision and values, but more of the -- how do you go about process of thinking about what is it we want to do? What is it we want to be?

That -- you mentioned the word process, that's a big word for us because how we do that is very important. We focus on the process that gets us to the outcomes that we desire. So it's about really getting everyone focused on how is it that we get to the most total shareholder return. And so those are very important to us. But I think -- I always knew that we had great people at ONEOK. But as you can imagine, after 7 or 8 years, a lot of those people have retired. So we replaced many of them. What I see is -- that really inspires me, gets me out of bed in the morning, is the way this company solves problems. So if you just look back at COVID in 2020, you fast forward to winter storm Uri, you then fast forward to this year, and we've had 2 major winter storms up in the North Dakota area. And then now we've had the incident at Medford. In each of those cases, what I saw people do is they came together and they problem solved. And they kept the product moving, and it allows us to basically do what we did on the conference call, which is reaffirm our guidance for 2022 even in the light of all of those things happening to us. So that's what gives me confidence in the future is our ability to problem solve whether or not that's going into transformation of energy and what we're going to do there or whether or not that's something that's thrown at us in the form of an event. So I really like our ability to problem solve. And I think that's what sustains companies.

Kevin, the Bakken, all have such a dominant position. When I think about acreage dedications, when I think about NGL takeaway, what's the landscape look like over the next 2 years, 3 years there? What do you think people get wrong? When they think about the Bakken, you're going to talk to investors through the course of the day, you do it all the time, but you also talked to, all day, every day, industry participants, producers, other midstreamers. How do you think about kind of what the landscape looks like next 2 to 3 years in the Bakken? And maybe where common perception of what's going to happen, may not align with kind of your own views?

I think we continually talk about granted the Bakken from a scale perspective may not be as big as the Permian. But when you look at the quality of the reserves, the longevity of the reserves, the drilling locations remaining, and probably, most importantly, the customer mix we've got up there with the who's who of producers, and they continue to allocate capital, and they continue to allocate meaningful capital to that basin. And so rigs have moved up to around 45 now. And more than 20 on our acreage, and that puts us in a position to grow gas production. When you combine the oil drilling with the rising gas to oil ratios, that provides us, I believe, visibility into natural gas production growth as we move through the next 2 to 3 years. And our customers aren't talking about the Bakken as a 2- to 3-year horizon, right? They're talking about it as a 7-, 10-year type horizon of production flat or slightly growing. So I think that's one of the misconceptions is, when you look at the market share we have up there from both a G&P perspective and probably more importantly, from an NGL perspective, and you look at that growth and the margins we realized up there, it just sets up a really nice story as we think about the next 2 to 3 years.

Kevin, can we unpack a couple of those? I mean, one, still a couple. I guess 1 that we get a lot of questions on really is on that kind of depth of inventory, and we've heard from some E&Ps, maybe in not so prime acreage or they don't have a lot, they had to buy things. What do you guys see as kind of the trajectory on kind of the ONEOK footprint in terms of remaining locations? How long that can run at kind of current rig count? Anything you can kind of frame that up in terms of inventory life?

Yes. We've -- the way we've talked about that is we still think there's decades of inventory left at $60. I mean, if you look at it, just the punch line, there's a lot of data points behind that. I think the biggest thing that's driven that number is over time, the producer has continued through technology and just understanding and testing out the various parts of the basin. More locations have moved down in their breakevens. I think Justin Kringstad from the state put out some information that over the last couple of years, 7,000 wells have been added to the inventory at less than $60, where, over the last 2 years, only a couple of thousand wells have been drilled, right? So we're actually adding inventory as we go based on the producers continuing to strengthen their technology from a drilling and completion perspective.

And then if we think about current activity right now gotten up to mid-40s rig counts, is this you kind of expect it to level out here? I mean no one has a crystal ball, but it's been a pretty big run. Obviously, still a healthy kind of growth on that kind of level. But do we look more to watch kind of completion crews ticking up? Do we have enough there? And how do you see activity going from these levels at least?

I think you'll see -- I do think you will see some continued strengthening. Do I think it goes to 60%? Probably not. But do I think there's still some rigs to be added, there's been a couple of producers talk about adding another rig starting in '23 or adding another rig starting in the fourth quarter. You've seen some M&A activity up there that we think might stimulate some activity, whether it's completing drill bit uncompleted wells that are out there on that acreage or adding rigs back with some of that acreage changing hands. So all those things, to me, point to some additional activity, assuming we stay in this type of price environment, which looks pretty stable at this point. But that's the way I would think about rigs. And -- but again, at this rig level, from a gas production perspective, we absolutely expect growth. And that's why we talked about on our call that if you stay at this level, we would expect more well connects in '23 than what we're guiding to in '22.

When we talk to investors, one of the common discussion points or things folks bring up is just a concern about gas takeaway. And I'll talk a little bit about that on the earnings call. Can you dive a little further into that? How does gas take away -- look, if you still have a lot of DUCs that are being worked on, and if you get in a couple of more rigs in the next 9 to 12 to 9 of 15 months, doesn't that make gas takeaway potentially the -- a knock-on constraint that would impact you all? And how do you think about what the producers or what you and your peers, the other guys who own assets there, can do to resolve that?

I think there's a couple of things just to remember about gas takeaway is Northern Border, which we're a 50% owner in as well, it's full. But there is still capability for -- as Bakken gas production increases from a residue perspective, it will continue to displace gas coming from Canada and that's just market. If you think the producers in the Bakken, the #1 reason they're drilling isn't what gas price they're getting for their MMBTUs. It's all about the crude. So the residue coming out of the Bakken, there's probably, we estimate 400 million a day of gas coming from Canada that can be displaced by the Bakken. So there's growth that can happen from that perspective. At the same time, Northern Border/TC Energy talked about on their call, there was an open season on a kind of Northern Border expansion, Bison reversal ultimately getting you down to a Cheyenne market. That's been favorably received by the market. They are in negotiations. And hopefully, I think they said, by the end of the year, we'll have some information on that. And that's a $400 million to $500 million a day type expansion. So that's out there that we think we'll get. There's been a couple of other smaller scale things that have taken place in the basin. You pull all that together, we absolutely believe that you're going to have enough residue takeaway as we think about the next 4, 5 years.

People often forget, Michael, a bit there was once a play up there called coalbed methane play in Wyoming. Lots of capacity got built basically from the Gillette area down to the Cheyenne area. Those pipes are basically almost sitting empty. So you don't have to go all the way from the Bakken to Chicago or the Bakken all the way to Cheyenne. You have a lot of infrastructure that's already there that you just got them through some short lays turn some reverses around and those kind of things. So there's probably more capacity there than what people realize. We're part owners in those pipes as well, which is Bighorn and Fort unit.

Maybe 1 more on that topic. And I know -- this has been something we've been working through for a while. Just any updates on the heat content in the northern border, where that could go? If we could kind of finally see NGLs drop out of that?

Well, again, it's really just a math problem. The gas production in the basin is getting back to the level right at, it's kind of bounced around a little bit, but where it was pre-COVID. Pre-COVID, we weren't recovering or incenting any ethane recovery out of the basin and the BTU level on Northern Border was around 1,100. And that starts to get to the point where something really needs to be done. Gas production's got back to that level, but we are -- we've had a lot of opportunities to incent ethane recovery, which has lowered the heat content going into Northern Border. So in effect, we're masking the problem at this point because we can, and it makes sense for us to recover that ethane. But if those economics change, and all that ethane ends up back on Northern Border, you're going to be right back to the 1,100 level. It's our understanding. They continue to work that, they being Northern Border/TC Energy, work that with shippers, with other processors in the region of some of the folks that had complaints also with markets continuing to understand what downstream impacts could that high BTU levels have on downstream markets, including utility companies, which are concerns that obviously we don't want to shift. Here's where I'd go though. In both of the scenarios, either just residue takeaway capacity or heat content, you can pick up additional capacity or lower the heat content by recovering ethane. So if we do end up getting short takeaway capacity, this happened in the Permian a couple of years ago before GCX and Permian Highland, some of those pipes came online. Everybody was recovering as much ethane as possible, not because it was economic, but because they didn't have residue takeaway. Well, you've got the option to -- if that would happen, if we miss the timing a little bit, or if the heat content gets to a point, you can always recover that ethane to lower the heat content or get you some more capacity from a residue perspective. So it sets us up in -- either way, we think we're going to be okay from both of those perspectives.

Came up on the recent earnings call earlier this week. Just curious, 2 things related to NGL takeaway. One, when you look at your crystal ball, how far out do you have to look before you think you're doing the Elk Creek expansion? That's question one. And then the question 2 is, when you think about tariffs on Elk Creek and kind of being able to get the -- sure it's down from kind of peak levels, but being able to get $0.25, $0.26, $0.27 a gallon, how do you think -- like if you were sitting in the producer shoes, what the breakeven of that is relative to the breakeven of them going back and thinking about, "Hey, maybe out of look at rail again." can you just kind of talk about those 2 things. The Elk Creek expansion, and then the economics from your customers had of kind of that $0.25, $0.26 tariff relative to other alternatives they may have?

Well, I'll start with that one. I understand the contracts we have in place up there were put in place maybe a year before Elk Creek, et cetera. Those were long-term contracts. So those contracts are going to be in place for years to come. At that point in time, assuming we don't extend term or whatever at current rates before then, you'll go back and understand what those economics are. We still feel very good that the netbacks you get from putting the NGLs on the pipe absolutely outperform other alternatives they have up there. So we -- I believe we continue to be the premium way to get NGLs out of the basin. So that is -- to me, is that question. On capacity, we'll watch it close. I mean if you look at our second quarter results, we've still got over 100,000 barrels, I think it's like 110,000 barrels a day of available capacity at its current capacity. Just to put that in context, that's filling up 4 plus 200-million-a-day processing plants and ethane rejection. So that's a lot -- that's equivalent of some 800 million a day of gas production that you still need to grow. So it's out there always. But that being said, we're always looking at it, particularly as it relates to the ethane option that if we see strengthening of that, then that might drive you there a little bit sooner. But regardless, we're talking about adding pumps, right? So we're not talking about -- we don't need a 2-year window to make that happen. You're talking months, not years in being able to get the pumps in place to expand that capacity. And we won't get caught short capacity coming out of the bucket, and that's with the market share and the margins we entertain up there.

I guess just 1 there. What would you need to see on the ethane side to be comfortable allowing higher recoveries to really underwrite an expansion, a pump addition?

I don't know that we would underwrite an expansion solely on an ethane play, if you will, but it absolutely factors into our thinking about what is that option value for having that capacity, right? We have a lot of confidence and expect to see C3+ growth in the Bakken just with the gas production growth we talked about earlier. So that would be the primary mechanism to me to drive the expansion and the timing, factoring in what is that ethane option value. And that will just come down to what's going on in the macro environment, what's going on with gas prices in Canada, what's going on with gas prices in the upper Midwest, what's going on with ethane prices in Bellevue, all those things would factor in just from a macro ethane supply/demand and natural gas supply/demand that would go into our decisions to expand the pipe.