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

Great. Good afternoon, everybody. Thanks for joining today. I'm joined by Pierce Norton, President and CEO; Walt Hulse, CFO; and Kevin Burdick, COO of ONEOK. Just before we get started, I want to make sure you're aware, you can ask questions during this session by clicking on the button on your screen and typing your question. That will come directly to me, and I'll ask that question on your behalf. So feel free to send those questions now and throughout the session. So Pierce, Walt and Kevin, thanks so much for joining today. Really appreciate it. I guess I'll kick off a few questions and then we'll see what we get from the crowd.

Why don't we just start with the obvious, I guess? Can you just give us an update on drilling activity in the Mid-Con, in the Bakken? How many rigs are running on your acreage right now? And I know a lot of the producers haven't really said what their plans are yet for 2022, but just curious, any kind of indications you have? And has anything changed with the move we've had in commodity prices over the last week or 2?

Michael, I'll take that. And yes, we've seen things in -- well, starting up north in the Bakken, it's played out very much like we anticipated. As we moved through '21, there was a large DUC inventory that as prices strengthened, that started to get worked down. That's continued to be worked down. As producers have gotten to their kind of equilibrium point of a normal run rate of DUCs, we've seen some of that capital switch back over to the rig side. And that's why we've seen the rigs jump up. I think we're still a little north of 30, and half of those, I think on our call, we said 17, were on our acreage. And we anticipate that will continue to strengthen a little bit, from what we're hearing. We've had a couple of our customers talk about on their third quarter call some strength in the Bakken with rigs. I think Hess was out there talking about maybe running some more rigs. Continental's obviously got a real strong position up there. And I think you'll see ConocoPhillips and Marathon and some of the other big ones, as we move into '22, I think they'll -- I think you'll see some additional activity from them as well. So the Bakken is playing out very much like we anticipated. And you combine that activity level with the rising gas-to-oil ratios, and obviously, we've got a lot of tailwinds up there for gas production growth in the basin. The Mid-Con has been -- obviously kind of even pre-COVID had slowed down, and COVID took it to basically 0. It has picked back up. The stronger nat gas and NGL prices has led to some opportunistic rigs showing up on the -- both the public and the private side. So I think that's been a tailwind, not so much on our G&P acreage, but with the expansive NGL system we've got in the Mid-Continent, pretty much any rig that shows up in the Mid-Continent, you can assume the NGLs are coming to us. So that's been kind of a nice unexpected tailwind. And then the Permian, clearly, there's been a lot of activity levels we've seen, as you've looked at our results really in all 3 basins, but particularly in the Permian, we've seen increased volumes, pretty substantial from Q1 to Q2 to Q3. We're hearing a lot of positive things from our customers out there about continued activity and strong well results. So we'd anticipate those volumes would continue to grow as well. So we're set up real nice as we move into '22 and beyond, and we'll see how it plays up.

Great. Just wanted to follow up with 2 points. One, just the recent change in -- the recent sort of downtick in commodity prices, do you think that has any impact on the outlook? I mean obviously, I think it's probably too early for -- to hear anything in real time, but just curious of your own opinion on that. And then the second kind of follow-up, you mentioned that the DUC inventory is being worked down a bit. So does that mean that on a go-forward basis, it's a little bit different of a relationship between rigs deployed and capital deployed for the producers versus production? In other words, aren't the producers going to have to spend more and put more rigs to work to keep production either flat or growing relative to just working down DUCs?

Yes. As we think about that last question, there's a couple of dynamics. They may have -- it all depends on producer by producer. They may have been running an extra completion crew to work their inventory down a little bit quicker. So as they add a rig or 2 back, they may back off a completion crew. So is that a 1 for 1 in capital? Obviously not. But it's not necessarily just a straight add because you don't necessarily -- you don't need as many completion crews to keep up with the number of rigs. So that's a shift. But again, those are producer-by-producer decisions just depending on how quickly or do they want to grow their production. There's 2 or 3 of them that are out public -- in the public domain saying they do want to grow production to a certain level and then hold it flat, crude production to a certain level and then hold it flat for a decade. So I think that's what you're seeing, is on a -- producer by producer will make those decisions. All of them are absolutely still adhering to -- they're going to live within their cash flows. They're going to return value to the shareholder and return those dollars to the shareholders. So that's why back to your first question, I don't -- we weren't panicking when crude lost $10 on the day after Thanksgiving or wherever -- whenever it was because we've kind of been saying all along, when crude pressed through $55, that was kind of, okay, we saw a lot of activity. Well, when it went to $80, we didn't -- it's not like rigs came flocking back. And as a result, when it goes back to $65, we're not -- I don't believe we're going to see rigs flock out of it -- of the basins, not just the Bakken but the other basins as well. I think there's a range in there that the producer is going to make really good money, and then the excess returns are going to get returned to the shareholders. But even in those, whether it's $55, $65 and maybe even $75, the activity, I don't know that you're going to see a lot of movement in activity levels assuming the producers continue to be disciplined like they're saying they are. And so far, we've seen that play out both as prices have moved up and prices have moved down. The one exception to price moves has been the Mid-Con that, that was to me kind of opportunistic as gas really strengthened hard and NGLs strengthened hard, that really made some acreage attractive in the Mid-Continent that I think you saw some rigs come back on a -- maybe on a more shorter-term basis depending on what prices do as we move through '22.

Maybe just following on that, clearly, with your outlook for volumes, I assume that's what drove you to restart construction on Demicks Lake III and the MB-5 fractionator. So my question is, is that just you taking care of your own volumes? Because I guess it surprised -- that announcement on the fractionator surprised us a little bit because we have been hearing just from others in the industry that there was a lot of excess or some excess capacity in the frac market. So a little surprising to hear you're adding a frac, but is that just something that's backed by your own volumes and that's how the economics work? Maybe I'll stop there and it's the first piece.

Yes. No, that -- I can see where that question comes from. And yes, there's frac capacity available today in Belvieu. Yes, we're taking care of our volumes. MB-5 was fully contracted when we originally announced it. So that means we had the contracts. They were -- the processing plants were in place to provide the volumes to fill it up, right? Well, the world changed with COVID. The biggest thing is that frac was 2/3 complete if you think about it, right? So when you look at the incremental capital we were going to spend, we absolutely considered going out and looking at third-party frac deals. Here's the rub. Yes, there is frac capacity available on a short-term basis at attractive rates, but nobody is willing to go do a 5-year frac deal or a frac deal with any term at those low rates. So we absolutely were running economics on a variety of different scenarios, different ways to provide that capacity. And at the end of the day, the incremental capital we were going to -- we needed to spend to finish off MB-5 was by far the most attractive. So that's why we moved forward with that.

Okay. That makes sense. I guess the final piece to this is really -- in my mind, at least, is Elk Creek. So kind of with the steps you've taken on Demicks Lake, MB-5, your -- I think the trends in ethane recovery that are probably in the midst of happening, how far away are you from needing to consider an expansion of Elk Creek? Or do you feel like there's just a lot of capacity there for a while?

Well, we've got quite a bit of headroom available. If you look at our third quarter numbers, we were at 315,000 barrels a day for the third quarter. We got 440,000 barrels a day of capacity, right? So that gives us quite a bit of headroom. If you think about that, that's like 4 processing plants would probably get you 100,000 barrels a day of NGLs. So you still got quite a bit of headroom before we would start considering an expansion. But the other positive for that expansion is we don't need a 2-year lead time to go ahead and expand the pipeline. You might need 9 to 15 months, somewhere in there, just depending on where the stations are because you're just talking about adding pump stations on the pipeline. So that allows us to wait, watch how volumes play out, watch how the ethane recovery dynamics play out, watch how the Btu spec issues on Northern Border. Over the next 1 to 2 years, I think we'll be looking at that real close. And I think you can be assured, given the economics of expansions, we're not going to get cut short on capacity on Elk Creek. So with the rates that we make out of the basin and in our position up there, we'll make sure we stay ahead of that.

Michael...

But we have a lot of capacity right now.

If you want to see all those numbers just on one piece of paper, we have those in our materials that we put out. So you can see just what Kevin has said, minimum capital can add another 100,000 to get us up to that expandable capacity at 540,000 barrels a day. So we're quite a ways away from them.

Okay. Got it. Maybe just one more question on the Bakken. It's a little more long term, and I guess it's one we get a lot from investors on one end. And that is, just how do you guys think about the reserve life in the Bakken and how that -- when you think over the -- I don't know how many years, but kind of the long-term cash flow profile of the company? And obviously, the premise of that question is that there's some kind of primate amount of reserves that's not that far out in the future. Curious how you think about that.

Well, let me start with that, and you can jump in here, Kevin. But I'd just point out that the Williston Basin has been there since, I think, around 1950, so we're going on almost 70 years of producing out there. The technology that they have today, the way they complete wells has really been able to tap reserves that was thought that you couldn't even get out of there. So I think you got to continue to look at improvements in technology over time. You think they can't get any better, they do. And then also I would say that there's multiple layers of reserves, too. I mean we're producing primarily out of the Bakken Shale play. But to the extent there's others out there, we have a saying in this business, Michael, that you find oil and gas where you found it before. And so I think you can always kind of go back to that and say that -- and we haven't talked about the gas-to-oil ratios. But as -- the way to look at that is that you're going to have these natural declines over a period of decades. But this gas-to-oil ratio, as you release some of the pressure, the bottom-hole pressure, you're starting to get more gas with the oil that's produced. So therefore, it acts in a way to minimize or to offset some of that natural decline. It's not 1 for 1, but it takes far less wells to be drilled in the future to hold the oil flat. And if the oil is flat, we will continue to see increases in the gas volumes just because of the gas-to-oil ratio phenomenon that's going on. So Kevin, you got anything to add to that?

No. I just think, Pierce, we've got -- we had -- a few months ago, Andrew and his team added a couple of slides that I think highlight that when you look at the gas production and the number of rigs needed to have driven that gas production. So another dynamic, as the wells continue to get more prolific, which has happened year-over-year, like Pierce said, that plus the rising GORs, you need less wells to grow production. Well, the other dynamic that's got is the fewer wells you need to grow production, the longer your inventory is going to last. So that's why we get real comfortable saying there's decades left of high-quality inventory left. It's this function of technology, the rising gas-to-oil ratios that you just don't need as many wells to grow gas production as you go out in the future. And that allows you to not deplete your inventory, which, oh, by the way, still continues to go up because the producers, as they work around the fringes of the play in the Bakken, they take their newest drilling and completion techniques and technology to those areas and all of a sudden, those areas are showing just as prolific wells as what we've historically called the core. So that's another way technology can just continue to expand the inventory as we move through time.

Okay. So I mean is it fair to understand, I mean I think the follow-up question that I think we always get also, which is it sounds like you kind of answered it already, is, do you feel like you need to ultimately diversify beyond the Bakken because of the potential reserve life issue? It sounds like the answer is no, but I just want to put a fine point on that from an -- I guess it's basically an M&A question.

Well, we don't feel like, Michael, that we need to rush out and do that. But I think any good business is going to always look for other opportunities. It's just a matter of what visibility that you might have to see what kind of growth is out there. You mentioned M&A. But we're fine with M&A, but we don't want to pay 12x, 13x EBITDA because of the opportunities that we have already and the capital that we can deploy. So if things were reasonable or if we felt like that we could see some visibility into how 1 plus 1 makes 3, might not be there right off the bat, but we know something out there that we have a good feel for it, then yes, we would -- we're going to always look at those kind of opportunities. But right now, our base business is our core focus, and it will remain our core focus.

Okay. Got it. I guess I wanted to talk a little bit, I mean, I feel like I mean the #1 topic these days for midstream investors is capital allocation. So I feel like if I don't ask the question, I'm not doing my job. Your leverage is coming down. And so I guess the question is, where -- at what point do you start making those capital allocation decisions from a leverage standpoint? And what do you need to see in order to resume dividend growth if that's kind of the preferred option for capital return?

Well, Michael, as we've said in the past, we are -- we do aspirationally want to get debt lower than where we are at that 4x at the end of the third quarter and aspirationally get somewhere in that 3.5 range. Clearly, as we get below 4, we will broaden our scope of things we are thinking about, but debt-to-EBITDA is not the only thought process that's out there. Given the fact that we've been increasing our dividend over the last 10 years at a rate that was well above the peer group, we still -- we already distribute a pretty large percentage of our free cash flow to the shareholders, probably more than most of the peers, definitely more than all those that cut the dividend. So from that standpoint, we are making that. And we think one of the other factors that we really need to be thinking about is a traditional payout ratio to earnings. And as we start to see that get below 100% and trend lower, our debt metrics getting into line, sure, we're going to continue to look for opportunities to think about things like dividend increases. And clearly, as we get below 4 and we start to reach some of those goals and they become clearly visible, then that's going to be a topic that the Board entertains -- they already entertain it quarterly, but it will be -- continuing to be a robust conversation.

So just to put a finer point on that, if you will, I don't know if you will, but where do you sit today -- from a payout ratio to earnings standpoint, if that's the right lens to kind of look at now, where do you need to be or what's the target where you get to that target and then you say, "Okay, now we're going to look at our options"? And where do you sit today?

Well, clearly, there aren't -- there isn't a norm because that hasn't been a focus of most of the midstream companies. You have a benchmark out there with utilities, which is one proxy you can think about. I don't know that that's the right one, but it is one to think about. We haven't nailed a number yet. Clearly, it's below 1 or 100%. And how far below, we're going to continue to evaluate. And we don't have to necessarily be at our end goal day 1. There's a discussion about the rate of growth of earnings and the rate of growth of dividend. You can still achieve some payout improvement while still at some point thinking about dividend increases, too. All we're saying is that there's going to be -- there needs to be a balance between those. And we think that focusing, as we're out talking to new investors that we're bringing into the stock, there's clearly a focus on earnings per share. And we've changed over our -- one of our short-term incentives to EPS per share, earnings per share because we clearly see that as a future focus of new investors.

Okay. Perfect. I wanted to talk a little bit about the Build Back Better bill. And I kind of had kind of a 2-part question really. One, just broadly, as you look at it, assuming it makes it into law in some form or another, which is, of course, a big if, is there anything in that, that you'd want to flag from a ONEOK perspective that's either positive or negative? And then specifically around methane regulations, there's a provision there, the methane fee based on certain thresholds you've hit, and of course, the EPA has a methane -- proposed methane regulation. So just curious how you think about that. Is that -- based on how it's written today, would you incur costs if that became law? That's kind of the first part of that. And then kind of on the flip side, could you benefit? I know you're already capturing a lot of flared gas, but does this put an even bigger impetus to get producers to stop flaring? So I know there's a lot in there, but...

Let me take the first shot at that, and I'll go in reverse order. But for the longest time, the producers, they prioritize the oil production over the flaring. Kevin will tell you emphatically that, that has definitely stopped, that they are laser-focused on getting to 0 flaring. It's about 6% to 8% right now up in the Bakken, which is our biggest area. But it's not -- it's still a big number as far as volumetrically, basin-wide or North Dakota-wide, it's still a couple of hundred million a day. So that's at least one processing plant. It's not all in one place. But I think that there's going to be a lot of focus on whatever we can do innovation-wise and continue to do what we do with our gathering business to try to lower that number. So I think that's the first one. As far as methane emissions go, Michael, I've had some calls with senators and congressmen to basically tell them there is a process, and it is the EPA process that we're very familiar with. We're regulated by them. And we would encourage them to let that process work because it does have these built-in periods where they do notice of proposed rulemaking. And so we get a chance to kind of shape that and other industry players do as well through the American Gas Association, INGAA or API, and kind of be very careful about what you're doing legislatively because there can definitely be some unintended consequences for the kind of the speed in which they do those kind of things. But right now, the stuff that's out there is the EPA, the people I've talked to, doesn't mean that they will not vote for it, but kind of behind the scenes, they do kind of indicate that they don't think that's necessarily the smartest thing to do, is to address this legislatively. Now there, again, no guarantees. It could come up for a vote, sail through just because they like something else in it. But there certainly seems to be a little bit of hesitancy from government officials that that's exactly the way to handle methane emissions. And we've already put out our target. We haven't committed to a 0 -- net 0 target by some date way out in the future because we don't see the technology to get there, and we're just not that kind of company. But we did say that from 2019 that by 2030, we're going to set a target of reducing our emissions by 30%. We don't do that without having visibility on how we're going to get there. It may not be all in 1 year. We may go a few years where it doesn't reduce, but then all of a sudden, we gain a lot of traction in other years. So to be a little bit lumpy how we get there, but we feel very confident that we can get to that point. So Walt, I'll let you kind of answer that if there's anything else in the Build Back Better bill that you think is going to impact us.

I think that you touched on it, that I think we can't hit hard enough that the customers out there are very serious about methane, getting all flaring down to that 0 and looking for all the ways that we can to capture all the methane possible.

Okay. Perfect. Well, I guess in the remaining few minutes we have here, I did want to touch a little bit on energy transition. I just want to get your thoughts on near-term, long-term opportunities that you're looking at. How much capital do you think you could be spending on energy transition going forward? And what returns would look like? And do they have to compete 100% with midstream? Or would you take slightly lower returns because of some of the other sort of ancillary benefits of energy transition?

Well, first of all, we do believe we're headed to a lower-carbon energy future. Michael, we are firmly in that camp. The way I describe this is that we're going to be very deliberate and intentional about what it is that we do. We do believe that using our assets and some skill sets that we have will be very beneficial to this lower-carbon world. We put it in 2 buckets. We put it into one bucket of emissions, which is how can we use our existing assets to lower the greenhouse gas emissions from other people. They call it renewable natural gas, but it's wastewater treatment plants, landfills, agriculture facilities, carbon dioxide emissions from electric generation and other industrial processes. We're looking at all the different technologies that are out there, and we feel like we can narrow those down to 2 or 3 that we won't have perfect visibility into, okay, this is the silver bullet. This is the magic thing that you can invest in, and this whole issue goes away. But we do feel like we can narrow that down to a certain number. The second bucket is resiliency, which doesn't have anything to do with emissions. But if you believe in climate change and extreme weather conditions, natural gas is positioned the best to address these various swings in temperature. We all hear about heating degree days, cooling degree days. That's the deviation from 65 degrees. Just one example of, we've never seen a sustained, like, 7-day period where the heating degree days were in the 70 heating degree day range, which meant that in Oklahoma, it was somewhere around minus 5 to minus 10 degrees for -- in an extended period of time. That ended up causing freeze-offs. So there's a lot of talk now about resiliency. We used to talk about affordability, reliability and -- but now you've got to throw in resiliency because they're critical facilities: hospitals, nursing homes, grocery stations, gas stations, that have to have backup power. And then how can we do that? Maybe in the form of backup generation, which takes natural gas or maybe it goes into a lot of the utilities right now are building these peakers that -- liquefied natural gas facilities to get them the extra capacity that they need for those short bursts that we're going to have. So we can't just sit here and say, "Okay, well, as soon as we get the greenhouse gas emissions down to 0, this problem has gone away," because that is decades and decades from where we are. Right now, it's trending up and especially worldwide. You can't put a curtain around the United States and say, okay, that China's emissions or Europe's submissions or anybody else's emissions is not going to eventually affect us as well. So we want to be prepared for that resiliency opportunity as well. So we're looking at business plans, understanding the capital, understanding the operating cost, what's the value to the customer, what's the impact to the customer, competitive advantage, and overall, what's the market size on this stuff? So we're taking a very deliberate and intentional approach. So we are -- we do have resources dedicated to this. But right now, I'm not seeing a material impact in the short term, which I'm saying is 1 to 2 years. There may be some more opportunities, especially 2 to 5 years from now and then 5 years and on, we may be looking at hydrogen and some other things, but it's a ways off.

Perfect. We've run out of time. So I just want to thank you for spending a few minutes with me this afternoon. And hopefully, we'll be doing this in person a year from now. In the meantime, hope you all have a very good happy holidays.

Great. Thank you. You, too, Mike.

Bye.

Thank you, Michael.

You bet. Thanks, Michael.