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

All right. This is the breakout session for ONEOK. Thanks for being here. I've got Pierce Norton, CEO; Walt Hulse, CFO; and Kevin Burdick, Chief Commercial Officer; and I think, Andrew, he's in the back, taking names. So I don't know if you guys wanted to make any opening comments or no?

We really don't.

Okay. Even better. So it's -- the floor is yours. So whoever wants to ask the first question, go right ahead.

Really, it's not going to be here? Nothing? Go for it?

[Indiscernible] debt market.

The debt market was very robust. We were about 10x oversubscribed when we first came out, ended up tightening our spreads by over 40 basis points from price stock. So there was a lot of demand for the paper. We had a maturity that we paid off in July. And so we have been running a little bit of commercial paper. We paid off about $300 million of it that we had just done from free cash flow. We did a little smaller deal. We intended to do $625 million, but there was so much demand that we went ahead in bid to $750 million. So market was very strong, very well received and spreads have tightened another 8 basis points since we actually issued it. We're very pleased. It was just a debt refinancing.

All right. I figure we'll start with some -- want to start with some macro? Petchem demands and -- Petchem margins have been weak, demand has been weak. Just wanted to get your thoughts on ethane margins have been pretty much close to 0. Just want to get your thoughts on what do you think is driving that? And do you see that improving Petchem demand specifically in ethylene margins in '23? Or what would drive that or not?

Yes. Clearly, the FERC spreads have come under pressure over the last few months. And as the global demand has pulled back a little bit and the crackers have pulled back on the utilization. So yes, that's pulled back the ethane recovery needed to provide that demand. That's global as far as where we think we're going to go from here. It's starting to maybe clean up a little bit. I mean, ethane and the last thing I read, ethane inventories had come back, had pulled down just a smidge. So we'll keep watching that. I think as you move through '23, I think you will see it clean up a little bit, and we'll see more recovery. But the one thing I'd just remind people is there's also the opportunity of what's going on with the natural gas price in the basin in the specific basin. And even at these FERC spreads, if you look at what's going on at AECO and Port Morgan and Empress and some of those places that's kind of the Bakken gas value, there still have been opportunities to in-cent recovery up there. So just because we're not seeing the generic FERC spreads widen out there, we do believe they'll continue to be basin by basin opportunities, just depending on what's going on with regional gas prices in that basin.

[indiscernible]

Okay. Well, Northern Border is still going to be the primary clearing mechanism for Bakken gas. There is still, we believe, an estimate around 400 million a day of Canadian gas, the dry gas coming out of Canada that can continue to be displaced from Bakken growth, we think that will happen. As we think about longer term, we referenced on our third quarter call that we picked up another 100 million a day of takeaway capacity on WBI that's going into kind of more of a Cheyenne type market. Northern Border is out with an open season that they're working through and interacting with various possible shippers on that expansion that would ultimately backhaul gas down Bison and then into a Cheyenne market as well. So we think near term, we're going to -- Bakken will continue to displace gas coming from Canada. And longer term, we've got a couple of these other things that we're looking at from a standpoint of making sure there's enough takeaway capacity in the basin.

So Kevin, nothing that I should add to your question, Lou, but you might talk a little bit about the BT.

Sure. As the BT -- as additional Bakken gas gets pushed into Northern Border, that will continue to raise the BTU content. If you rewind pre-COVID, Northern Border had actually put forth a tariff change or that involve the BTU specification or a spec on the BTU content. FERC rejected that and asked that Northern Border go back and work with shippers and markets and producers in the region to ensure that it was the right solution and the right tariff level. They're in the process of doing that. But it's really just math as additional Bakken gas gets pushed into border. It's displacing lower BTU content gas coming from Canada, which elevates the BTU on the pipe. The problem is with that situation is downstream markets, particularly LDCs that pull gas off of northern border, need a lower content -- heat content gas. So if we run into problems, we can -- one way we can help that problem is to recover ethane. So we've been -- with the ethane we've been recovering over the last several months, incentivizing that recovery. We've really been masking and lowering the heat content on the pipe artificially. If those economics change and all that ethane gets pushed back into Northern Border, then it's going to exceed kind of the downstream needs of those markets. If that happens, then we're in a situation where we could potentially have to recover ethane on a required basis at which time we'd get full rates for that ethane instead of the incentivized ethane we're doing right now. It wouldn't -- well, what would happen is if all of a sudden the downstream markets start saying we're not accepting the gas, the Northern Border would have to step in or has the ability to step in and issue a flow order that says, no, okay, we have a change in operating conditions. So we're going to need to, on a short-term basis, implement some necessary precautions to keep it from happening. But the long-term goal is that ultimately, Border would have a specification that would control the BTU level that's coming into the pipe.

So just a follow on since you've brought up Northern border, we'll just go with that. I guess knowing everything that you just described, what -- like why isn't the expansion of Northern Border moving forward? It seems obvious to me that it would. I guess is it the same shippers that would be signing up for that, that would be forced to remove ethane? Or is it a different set of shippers, so maybe like their incentives are not aligned?

All right. Again, we're not in the middle of those. But understanding, I think what's going on is people are just talk thinking through for their specific -- the shippers in out of the basin or thinking through what's the timing they need this? Is it on the same time frame that border is looking at it? What's the term on those things. Then ultimately, what's the rate? What's that do to the Cheyenne market if you start pushing gas. So I think it's what I'd consider kind of the normal kind of marketing, negotiation, understanding of what's needed from a commercial perspective to make a project like that go. And then there's just some back and forth. But clearly, we are involved as a shipper from a gathering and processing perspective and as well as a 50% owner on the pipeline.

And Michael, there's also been some announcements of some in-basin demand there are a couple of power plants that have been announced that could be built in the basin, which would absorb some additional gas.

So I guess since we jumped right to the Bakken, we I'll just jump right to the Bakken. Maybe you could just generally just comment on what you're hearing from Bakken producers? How high you think the rig count could get this year? And any early read, I don't know of what you'll give me here, but any early read on what that would imply for '23?

Well, I think you've got -- you've definitely got some tailwinds that we talked about on our third quarter call. You're sitting north of 40 rigs in the basin, north of 20 of those are on our acreage. We've talked about -- we really only need about 15 rigs on our acreage to hold gas production flat. So clearly, at more than 20 rigs, we are definitely on a growth trajectory relative to '22. Recent conversations even with a little pullback in crude. I mean, there's been no conversations of reducing activity. There have been a couple of producers talk about as they move into '23. And move, especially as you get out of winter. Could there be some additional rigs. Does that -- do I think it goes to 60 rigs? No. But does it maybe get near closer to 50 than 40? Probably so. But at that rig level, you've got enough activity to probably slightly grow oil. And so gas production with the rising GORs is going to continue to grow more than that. So I think that's the tailwind and producers have been extremely transparent because of the flaring. So there's a lot of information we get from them to get comfortable with where activity levels are going, and that's been a strong positive for us. And again, all indications at this point given the strip we're looking at and the rigs that are already there and possible more rigs. But that's why we feel strong about the outlook we provided on our third quarter call.

[Indiscernible]

We still have very frequent and consistent conversations with them. I'm not going to speculate on what they may or may not do. But I think the interesting dynamic, just from my opinion is they've recently kind of expanded their portfolio to the Powder and to the Permian, and what they do to that. We've seen no pullback at all of capital for the Bakken. And so I expect the Bakken to continue to get a really nice allocation. To me, the question is, does it possibly even get more capital put to work in the Bakken.

Maybe just a couple of things you mentioned. So you've been, I think, I would think you'd say this a beneficiary of the trend in higher gas oil ratios even as oil production in the Bakken has kind of flattened out, but gas production is still growing. Also, the reduction in flaring over time has been an opportunity for you. Where do you think those 2 things stand, meaning like is the GOR is continuing to grow? Or is it sort of hit its cap and on the flaring side, I mean, the basin has done -- made a ton of progress. I think you have a chart in there that shows that I mean how much more is that you go in those 2 if any?

Clearly, the bigger -- to me, the more material thing there is the gas-to-oil ratios. All this -- we've talked about before, all the studies we've done. We've had third parties do studies, the state of North Dakota has done studies, producers have talked about the rising gas oil ratios. So we absolutely believe that's going to be measured in years that we believe the gas-to-oil ratio will continue to go up. Some years, it may be a little shallower growth. Other years, it may be a little greater just depending on where the activity is, how much activity and so forth. But absolutely, when we think down the road, even we've talked -- you probably have heard us go through the math, even if the gas to oil ratio goes up one turn. So let's say it goes from -- when we started talking about this, it was 2.6, now it's already at 2.8. So if it goes -- if it went from 2.6 to 3.6, so if it just goes up on turn, that drives an additional Bcf a day of gas production if you're assuming 1 million barrels of oil flat in the basin. So backing into then some of the other sensitivities we provided a Bcf a day is about 5 new processing plants to handle 200 million cubic feet a day processing plants. Each processing plant produces roughly 25,000 barrels a day of NGLs. That's about $100 million a year of EBITDA for us with those NGLs coming down the pipeline. On the gathering and processing side, we're roughly half the basin. If you do the math, and that's another $250 million of EBITDA for the gathering and processing business. Put those two together, one turn provides us the opportunity for about $750 million of EBITDA growth over that time frame. So whether that's 2 years, 3 years, 4 years, that remains to be seen, but we absolutely believe at least one turn is probably a very conservative kind of outlook of where we think the gas-to-oil ratio could go.

Maybe if we talk a little bit about the '23 outlook. You provided 10%-plus growth. Can you just talk about what the main drivers are there? And maybe some of the underlying assumptions in terms of commodity prices? Or what are you assuming in terms of recessionary risk? Things like that.

Well, I'll start and these guys can chime in. We talked about on our call that really, as we think about '23, it's a volume story that we communicated that we believe our volumes will be up year-over-year in all 3 of our basins primary basins. We think of the Bakken, the Mid-Continent and the Permian from an NGL perspective and also from a G&P perspective in the Bakken and the Mid-Continent. So -- and that growth will occur at activity levels we're experiencing today. So we don't need to see an influx of rigs or completion crews to meet those volumes that we have factored in as we think about our outlook. Ethane recovery will play a part of that. We've talked about our ethane recovery assumptions that the Permian will be in full recovery and the Mid-Continent will be in partial recovery, and we'll have an opportunity to incent some ethane out of the Bakken. And then the last thing I'd point you to, if you just look at -- in our G&P business, that we're getting a price help because just looking at the price, the hedges we had in place in '22 and compare those to the hedges we have in place in '23, just that uplift is north of $50 million. So those are a handful of the drivers that as we think about '23, why we got really comfortable with saying we are going to see the double-digit growth.

[Indiscernible]

We talked earlier about the Petchems. Sure, we'd love to see that FERC spread widen out sooner rather than later. But on the flip side, there's a lot of dynamics going on with gas prices right now as well that are providing us opportunities. And I'm stealing something that Walt usually reminds me to say, so I'll remember this time. But when you think about -- when we talk about incentivizing Bakken ethane, if you think about if we recover ethane just economically in the Permian, that's just a normal contract and the most you're going to get is based on the contract, which may be, let's say, $0.07 or $0.08, okay? In the Bakken, when we may be incenting recovery, which just means we're not charging full rates, okay? Well, the starting point for the rate out of the Bakken is $0.30. So when we say we're incentivizing ethane, we may be realizing $0.15, which is twice as much as we would be getting in full ethane recovery in the other basins, primarily the Mid-Continent and the Permian. So that's one thing. I'm not sure that people really continued -- we're trying to continue to send that message that when we talk about incentivizing Bakken ethane, we're going to compare the gas price in the basin to what the Belvieu ethane price is, and we're going to come in right under that to determine, okay, it makes more sense to pull it out. But we may be getting $0.10, $0.15, even more money, more cents than that per gallon?

One thing I'd add to that is that when you talk about headwinds kind of put them into categories like hurricanes. You can have kind of a slight headwind or you can have some major headwinds like COVID-19, it was like Cat-5 because everything kind of shut in. But because of some of the things that are going on in the environment, our storage is more valuable than it used to be. [indiscernible] guys are doing a great job of re-contracting that and even adding to that. So those kind of things help us. A lot of the things that we're doing environmentally to reduce our CO2 emissions is actually helping in actually has economics to it because you could replace old obsolescent gas part units on our transmission system and enroll that through in rate cases and those kind of things. So there's a lot of things, there's a lot more tailwinds kind of happening to us than the headwinds. I think China coming out today, and they're loosening up some of their COVID restrictions, left to be seen exactly what that's going to do and how that trickles through the overall global but that's better than what they were doing. So I think that's a positive. So there seems to kind of be more tailwinds than there does the headwinds.

So we'll get there. Just -- maybe just one follow-up to this discussion. So you said your guidance does assume recovery of ethane in the Permian and partial in the Mid-Con. So does that mean, effectively, you're assuming some kind of recovery in ethane spreads basically Petchem demand recovery. So it doesn't -- so it assumes some kind of reopening in China and some underlying assumptions there around just the global economy. Is that fair?

I mean, yes, I think we'd see it maybe a little bit stronger. But again, I think we've seen enough volatility in the gas price basin by basin over the last several years to not necessarily get locked into what happens in the macro, therefore, has a direct correlation. Absolutely, I'm not going to deny that there's an influence there that we would love to see stronger spreads. But it also seems like periodically, things -- those -- the gas prices and/or ethane prices in Conway or Belvieu will just get a little out of whack and provide opportunities. And with our integrated footprint, we've got the ability to capture those as soon as they happen.

And if you take ethane of the equation, which is really the one that would be somewhat sensitive to the economy, the rest of our volumes, as long as crude oil is produced, the volumes are going to be produced, and we're not -- ultimately they're drilling for crude. So there are price takers on the other commodities. So the throughput that we get will continue. So we really only see that global recession issue in the ethane.

[Indiscernible]

To be honest with you, there really isn't. We -- I think that obviously, time has gone by. And so we're clearly closer to making a decision of what we're going to do. We continue to work very well with the insurance company. As you know, we received an upfront $100 million distribution from the insurance companies. it was unallocated. That kind of took care of us from a business interruption insurance through the fourth quarter. So we don't have any immediate need for recovery on that front. And -- but -- we're getting close, but we we'll make our decision as soon as we have all the facts in place and come to a conclusion. But we're working very well with the insurance company.

Maybe just a follow-up on that. I mean, timing-wise, when do you make a decision, how long will it take you to either rebuild at that location or build something new on Belvieu or somewhere else?

Mont Belvieu would be significantly faster. We have all the permits in place, for Mont Belvieu. We actually are finishing MB5. So we have construction workers on site. We've got all of the infrastructure in place. So there would be a meaningful difference in the time. Now there would also probably be a difference in cost. So those are where the trade-offs are. And obviously, we have business interruption insurance that runs throughout whenever we get capacity back. So those are the discussions we're having with the insurance companies is how you balance the business interruption versus the cost of a new [indiscernible]. And I expect to get there in the not-too-distant future. I'll be the first to know when we do.

Okay. [indiscernible].

Carefully. What's economically the best answer is, we are somewhat indifferent between the 2 because they both have pros and cons, they both give us different opportunities and options. So it's going to be what is the best economic benefit for.

That's helpful.

It's stupid. I just -- you said yourself up.

If I just push a little more on this one, can't help it. If you chose to build -- basically add capacity at Mont Belvieu, what does that do in terms of the flows or arb opportunities on Sterling? Is that part of the equation in terms of looking at the total economic impact and returns?

Sure. Yes, it is.

Maybe a couple of corporate questions. One, you sort of strongly hinted at dividend growth for next year. Those are my words, not yours, but...

That is your words.

Yes. Okay.

I think what I said is that -- but up until this point, our debt-to-EBITDA ratios were 4-plus something that we focused on a lot in the last 1.5 years is what's that payout ratio. So would it be in over 100%. It doesn't -- it limits you on those capabilities you have in your capital allocation model. So what I was seeing was that as that debt-to-EBITDA gets down and if you do the numbers, you can back into, you're probably talking mid 3-point something. And then you're looking at a payout ratio that's coming down below 100%. So now it's opening up other levers for us to pull that we maybe just didn't -- couldn't consider prior to that. So it just means that we've got all the levers kind of at our fingertips now, not just simply one. I think others like yourself kind of pointed towards that, but that doesn't necessarily mean that, but that's kind of where we are.

So maybe a couple of follow-ups on that. So -- and again, just correct me if I got it wrong. I get a lot of things wrong. The -- I remember when you first started talking about this, the payout ratio concept and looking at that as the framework. I thought the idea was well, we want to get something closer where utilities are as a comp, and then we would consider increasing dividends. Is that fair, or is that not, I mean, you're not going to get there. I don't think anytime soon.

I think what we said was that weren't going to get to where a utility was, but somewhere between where the utilities were in 1% and 100%, that's probably in the range.

And then just as you think about the dividend and dividend growth, is the fact that interest rates are up, there are other competing securities now that give you a pretty healthy yield, is that at all -- does that make you feel like you need to potentially compete on a yield basis more than in the past when interest rates are really low.

Yes. I mean we're not hearing that the -- that our yield is lacking in any fashion. And if you look at our return of capital to the shareholders as a percentage of free cash flow, it's still probably on the higher end compared to a lot of our peers who cut their dividends. So we feel like we are returning. But if we do start going back towards a dividend increase, it would be more to get a sustained view of a future growth pattern as opposed to we're not hearing a lot of shareholders saying that we're not -- our dividend yield isn't competitive at this point. So I think people are reasonably pleased with it, but as Pierce said, our flexibility is definitely increasing.

So maybe the flip side of this is the -- this new AMT is clearly coming. So if you could just remind us where do you think you're going to be -- when do you think you'll be a cash taxpayer, what offsets you might have to reduce that below 15% and kind of how that all -- what's your latest [indiscernible]?

Well, we are a cash taxpayer today, just a very low cash taxpayer. The NOL prior to the Trump Tax Law we could use to shelter 100% of our income. Once we used up that NOL, then there was a limitation that only 80% of our pretax income could be sheltered. So we were effectively paying 21% on that 20%. So we're a little over 4% cash taxes. When we jump up, we will jump up to the 15%. I don't see us ever going to the 21% statutory rate. You have to remember that the test period started in 2020, and in 2020, we put in Arbuckle in the service, Arbuckle II, MB-4 and Demicks II. So we put in a significant -- a couple of billion dollars worth of assets that we took bonus depreciation on. And then as we go into 2023, we will put into service MB-5 and Demicks III. So we will have another over $1 billion worth of assets coming into service. So we will get bonus depreciation on that. So we still will not be in a situation where we will be up to that 15% tax rate for a number of years. But we were previously -- prior to this law, we had an expectation that we would ramp up to 21% at some point. Given the way it is written, we don't expect to have that ever happen. And the reason for that is that because we'll get -- we'll start paying the 15%, the NOL will go, will effectively be pushed forward and will use the NOL for a longer period of time.

Your last chance to ask questions, there's 1.5 minutes? Anybody?

What are you going to do with the next meeting?

Go ahead. Go ahead.

How do you think about the per talk about the Bakken or is there a risk that the Permian [Indiscernible]

We still think -- I mean, we still think there's a lot of growth left in the Permian. It's just such a big play. Midland, Delaware, our West Texas LPG system connects both of those subbasins. We're seeing a lot of activity in both granted, we don't have the G&P presence out there, but we've still been able to compete and get our fair share of the NGLs and grow nicely. We've talked about our expansion earlier in the year that we completed the night, the beauty about that pipe and probably the reason we don't say we probably should talk about it more, but we don't is we can continue. We're expanding that pipe by looping it from the Permian over to Arbuckle II. If you think about Arbuckle II from effectively Fort Worth to Mont Belvieu. So the pipe goes from the Permian, say, over to Fort Worth, so west to east and then it goes south, and it also connects to Arbuckle II at that point. Arbuckle II can be expanded up to 1 million barrels a day. It's currently 500,000 barrels a day, but we can expand it expanded to 1 million barrels a day by just adding pumps. So the way we get more capacity out of the Permian is we can just add loops or redundant pipe in constrained spots. And we do that just on -- we can add 25,000 barrels a day here, 40,000 barrels a day here as we either get new contracts, or as volume starts to show up, those projects typically will take somewhere between 6 and 12 months. And they're not long lead type projects. And then once we continue to loop that at some point, we will have looked or built new pipe all the way from the Permian to Arbuckle II. At that point, when we get that whole new pipe built, we pick up an extra couple of hundred thousand barrels a day of capacity. So that's how we believe and we've been successful in competing. We can compete on speed. Typically, we don't need extremely high rates as we look this thing incrementally, and then at some point, we're going to get to the point where we'll go ahead and finish it off. And now we've got a brand new 24-inch pipe from the Permian to Arbuckle II, and we can connect on into Belvieu. And lastly, our West Texas natural gas pipeline system, our intrastate, the gas pipeline system has been and extremely valuable. It's really kind of a large header system in the Permian. And we've expanded that thing. I've lost track, probably 4, 5 times. We've expanded storage once we're looking at opportunities to further expand storage as that pipeline really has been a productive asset for us as the Permian has grown.

Great. This has been wonderful. I really appreciate the time, and thank you. Thank you.

Thank you, Michael.