Oneok Inc (OKE) — Q1 2022 Earnings Call Transcript

Thanks, Andrew. Good morning, everyone, and thank you for joining us today. We appreciate your interest and investment in our company. On today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Investor Relations and Corporate Development; and Kevin Burdick, Executive Vice President and Chief Commercial Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President of Natural Gas Liquids and Natural Gas Gathering and Processing; and Chuck Kelley, Senior Vice President of Natural Gas Pipelines. Yesterday, we announced first quarter 2022 results, which highlighted year-over-year natural gas and NGL volume growth. Earnings significantly increased year-over-year when adjusting for the favorable Winter Storm Uri impact in the first quarter of 2021. Customer and producer conversations continue to point to additional activity through the remainder of the year, supported by strong demand for U.S. energy and commodity prices far exceeding basin breakeven economics. Our built-in operating leverage and proven track record of disciplined and intentional growth have positioned us well to support increasing producer activity levels. Our systems have significant capacity to grow alongside the needs of our customers. And because our large infrastructure projects are complete, we now have opportunities for bolt-on expansion projects with quicker in-service dates, attractive returns and minimal capital requirements. Not only are we expecting strong activity going forward, but our position in the key U.S. shale basins provides us a long runway to continue our efforts to help address increasing domestic and international energy demand. Current events continue to demonstrate the importance of natural gas and natural gas liquids in a long-term energy transformation and highlight the critical role that ONEOK plays in providing essential energy products and services. Before I hand the call over, I'd like to discuss the recent weather events that have impacted our Rocky Mountain region operations in April and into early May. First of all, I want to thank our employees in the area, and those who supported from other locations to ensure that we were as prepared as possible for these two unprecedented winter events within a two-week period. The severe April storms caused blizzard conditions, record-setting snowfall, high winds, and extensive power outages across North Dakota, Montana, and South Dakota. A number of our employees staffed facilities during these conditions to maintain the safe and reliable operations of our assets. Many of these employees were also dealing with lost power and damage at their own homes. Widespread outages left many of our facilities without power for several days and a significant number of wells across the Williston Basin were shut in. Our primary focus has been on the safety of our employees, assets, and the communities where we operate as we continue to work through the full impact of the storms. Due to the basin-wide power outages, our April Rocky Mountain region volumes were reduced in both our natural gas gathering and processing and natural gas liquids segments by approximately 20%. May volumes will continue to be impacted as down power lines are replaced. Currently, our process volumes are more than 1.1 billion cubic feet per day, and our NGL volumes are more than 320,000 barrels per day and trending up as shut-in wells are brought back online. The coordination during and since these weather events with our customers, local agencies, communities, and other operators in the area has been impressive, once again highlighting the resiliency of our employees, assets, and our customers. Even with this late winter storm, we are affirming our financial guidance ranges and midpoints for both adjusted EBITDA and earnings per share. With that, I'll turn the call over to Walt for a discussion of our financial performance.

Thank you, Pierce. ONEOK's first quarter 2022 net income totaled $391 million, or $0.87 per share, a 24% increase compared with the first quarter 2021 when excluding the benefit of Winter Storm Uri. First quarter adjusted EBITDA increased 11% year-over-year when excluding Winter Storm Uri. We ended the first quarter with a higher inventory of unfractionated NGLs, primarily due to timing, and expect to recognize those earnings in the second quarter as our current inventory is fractionated and sold. Our net debt-to-EBITDA on an annualized run rate basis remains below 4 times, and we continue to view 3.5 times or lower as our long-term aspirational leverage goal. In April, Moody's updated ONEOK's rating outlook to positive and affirmed our investment-grade rating. ONEOK maintains investment-grade ratings with Moody's, S&P, and Fitch. As Pierce mentioned, the recent extreme April storms have impacted our operations in the Rocky Mountain region. But even with these weather impacts, we are affirming our 2022 financial guidance. Strong volumes prior to the weather impacts, strengthened drilling activity, DUC completions through the remainder of the year and a positive outlook for NGL and natural gas demand this year points to a strong volume exit rate in 2022. I now turn the call over to Kevin for a commercial update.

Thank you, Walt. During the first quarter, we saw double-digit NGL volume growth across all our operating regions compared with the first quarter 2021, and Rocky Mountain region natural gas processing volumes increased 11% year-over-year. After reporting record Rocky Mountain region natural gas and NGL volumes in the fourth quarter 2021, we saw volumes decrease sequentially in the first quarter 2022, primarily due to normal seasonality across our operating areas. Through the first four months of the year, we've continued to see encouraging activity from producers, and we expect these activity levels to trend higher through the remainder of the year. Let's take a closer look at our natural gas liquids segment. Total NGL raw feed throughput volumes increased 17% year-over-year supported by increasing producer activity and increased ethane recovery. Rocky Mountain region NGL volumes increased 24% compared with the first quarter of 2021. In April, we reached peak volumes of more than 385,000 barrels per day from the region prior to the severe late-season storms Pierce discussed earlier. Mid-Continent NGL volumes increased 10% year-over-year. As producers continue to increase activity in the Mid-Continent, a large majority of those related NGLs are transported on our system. So far this year, NGL volumes from the region are trending slightly higher than we had originally planned. In the Permian Basin, NGL volumes increased 23% year-over-year due to strong producer activity levels, which feed our West Texas NGL pipeline. In the Gulf Coast, construction continues on our 125,000 barrel per day MB-5 fractionator in Mont Belvieu, which we now expect to be complete in the second quarter of 2023. MB-5 will increase our total system-wide fractionation capacity to more than 1 million barrels per day. International LPG demand remains strong, and we continue to expect both domestic and international ethane demand to continue to increase throughout 2022. As natural gas prices have increased this year, ethane prices have kept pace, providing attractive ethane recovery economics in certain areas of our system. While first quarter ethane recovery is typically lighter due to natural gas heating demand and typical winter weather impacts, we see strong ethane recovery opportunities for the remainder of the year. Moving on to the natural gas gathering and processing segment. In the Rocky Mountain region, first quarter processed volumes averaged 1.3 billion cubic feet per day, an 11% increase year-over-year. In April, volumes reached a peak of more than 1.4 billion cubic feet per day prior to the storms. We connected more than 90 wells in the region in the first quarter compared with 38 connections in the first quarter 2021, and are on pace to meet our guidance midpoint of 400 well connections in the region. There are currently 38 rigs and 12 completion crews operating in the basin, with 17 rigs and approximately half of the completion crews on our dedicated acreage. This continues to be more than enough activity to grow gas production in the basin and on our acreage. Additionally, the basin-wide DUC inventory remains at approximately 500, with half of those on our dedicated acreage. Recent reports from the North Dakota Pipeline Authority highlight the long runway of core drilling inventory remaining in the Williston Basin. Enhanced drilling and completion technologies are significantly increasing the basin's core acreage and further extending the decades of profitable drilling locations remaining in the region. The core acreage in the basin has expanded by an additional 3,000 square miles, with more than 7,000 drilling locations added to inventory that are profitable at crude oil prices of $60 per barrel. In the Mid-Continent region, we continue to see increased activity with 3 rigs now operating on our acreage and 45 rigs basin-wide. We continue to expect increased natural gas processing volumes from the region compared with 2021 and expect the majority of rigs basin-wide to drive additional NGLs to our system. In the natural gas pipeline segment, strong first quarter results benefited from increased natural gas sales and higher seasonal volumes compared with the fourth quarter 2021. We continue to see strong demand for natural gas storage services and are working to expand our facilities to meet this increasing demand. We recently completed a 1.1 billion cubic feet expansion of our Texas storage facilities and announced an open season to increase our storage capabilities in Oklahoma, enabling an additional 4 billion cubic feet of storage capacity to be contracted. This project is expected to be complete in early 2023. We also recently announced two open seasons for additional pipeline capacity to address increased demand, one on our WesTex pipeline system in the Permian Basin, and one on our Viking pipeline in the Upper Midwest. We continue to work with customers across our natural gas pipeline network to address their evolving transportation and storage needs as these key assets continue to provide value year-round. Pierce, that concludes my remarks.

Thank you, Kevin, and Walt. The overall dynamics in the midstream space and for ONEOK specifically remain positive. We increased activity, strengthened demand, and available system operating leverage. The U.S. energy industry is well positioned to be a significant source for domestic and global natural gas and NGL supply for the long term, with midstream playing a vital role in the safe and responsible transportation of these vital energy resources. As we continue to help supply our country and the world with low-cost energy, we are also looking to play an important role in the transformation to a lower-carbon future through best management practices and collaboration with customers and service providers. We are addressing the growing need for energy products and services today while also preparing for a long-term energy future. It's this innovation, resiliency, and dedication of our employees that makes ONEOK a leader in our industry, and with the positive momentum we're seeing in our business and the increasingly positive outlook for the remainder of the year, we're well-positioned for yet another year of volume and earnings growth. With that, operator, we're now ready for questions.

This is Steve speaking on behalf of Jeremy. I wanted to begin with a pertinent question about the weather. In the release, we mentioned achieving 1.4 million cubic feet per day in the Bakken. Is that an average figure, or did you reach that level, and how is it trending now given the current conditions there?

This is Kevin. We reached a volume that we indicated, which is not the average for April. We wanted to share a figure that reflects the available gas. On several days before the storms hit, we were at 1.4 Bcf a day, illustrating our trend at that time. In my earlier comments, I noted that currently, we are at about 1.1 Bcf a day, and that number is increasing as we bring the wells back online.

And then next one, I guess, we'll go to the GORs. I guess I just kind of want to get some feedback there on how you're seeing those trending as new wells get drilled. Are they maintaining kind of that GOR level? Or are they becoming, I think, more oil-based at early stages and just how you're kind of seeing that go?

Yes. When you examine the trends over time, the gas-to-oil ratios have been increasing, with a figure of approximately 80% since 2016. You might notice some minor fluctuations as new wells are introduced. The gas-to-oil ratios tend to rise over time for individual wells, and there are variations across different regions of the basin. However, there will be some short-term dynamics that change from month to month as new wells come online and drilling takes place in various areas. Overall, the general trend is that the ratio will continue to rise.

Maybe just to start off on operations. I was wondering if you could talk a little bit more about the completion guidance for this year. We saw roughly 90 wells completed, which kind of indicates that roughly 25% of the well completions were done in 1Q per the guide. So typically knowing that most of the well completions were no back half weighted just due to natural seasonality, I was curious if you could see some upside to that well completion number particularly as producers, specifically the private took to take advantage of the current pricing and rigs start to materially come back into the basin over the balance of '22?

Brian, this is Sheridan. I would like to mention that we are maintaining our previous guidance on well connects. However, as you noted, starting the year with 90 well connects is a strong beginning.

The natural gas segment had a strong performance this quarter. Could you discuss the future recontracting opportunities, particularly regarding the Permian and the West Texas system, considering the tightness in Permian natural gas? Are there chances to expand WesTex similarly to what we experienced in 2018?

Chuck, do you want to take that one?

Yes, surely. Brian, this is Chuck. So as you said in 2018, we had an expansion, we also recontracted. We're seeing right now similar opportunities for this year. We're currently working on an additional expansion opportunity beyond the open season that's listed on our website, that'll be moving Permian gas north as well like we did in 2018. So that's an incremental expansion. And then on recontracting, we see some really good recontracting opportunities this year, somewhere in the neighborhood of up to 200 million a day on recontracting.

I think you mentioned that NGL volumes in the Bakken reached 385,000 barrels per day prior to the winter weather. So I mean that's an 88% utilization rate on your NGL pipe. So I guess my question is, why aren't you moving forward with an Elk Creek expansion at this point? Are you waiting for utilization to get closer to 100% or waiting to see what happens with the gas pipe expansion? Just trying to get a better understanding of your thought process behind an expansion.

Praneeth, this is Sheridan. When we look at the expansion, we look out forward and see when we'll need it, when we need to start commissioning that expansion. And you've got to think about that we have about 440,000 barrels a day today and at 385 that has quite a bit of incentivized ethane in it. So we can kind of swing on that as well. So we continue to look through our gathering and processing, what's going on in the basin when we need to expand that and when we need to expand the capital. And right now, we're sitting today, we think, in the short term, we have enough capacity on the system to handle what we need going forward, but we continue to evaluate the opportunity to expand and make sure that we put ourselves in a position that when it is time to expand, we can expand it quickly.

And then I wanted to ask about the rate case on the Guardian pipeline. If you could just ballpark the magnitude of the rate case, and how you intend to proceed? Would you expect to settle with shippers? I mean I know you're probably limited in what you can say, but just any clarity would be helpful.

Chuck, do you want to take that one?

Got a connection problem. But as we look at the rate case, yes, it's not going to be a big deal at all. When I say a big deal, it's not going to be material in terms of where we're at from a rate and where we might go. Yes, those typically will evolve. We'll do our best to work with the shippers on the pipe and come up with a rate that we feel is appropriate and move forward. But it's not going to be meaningful to our overall EBITDA.

Just a follow-up on Pierce and Kevin's comments. It sounded like 1.1 the as of processing currently versus the 320. So I think on the processing side, still down about 15% versus Q1, but actually up for NGL. So one, I just wanted to clarify that that's what you mentioned in terms of incentivized ethane. And then, two, interested in your thoughts on whether we're seeing a more structural shift or primarily due to pricing volatility over the last month or two?

Colton, when you say structural shift, I'm not sure I'm following that question on the pricing.

Yes. Kevin, I think you mentioned that you see ethane opportunities over the balance of the year. So I guess I mean it seems like that would imply that you are seeing a pull on ethane. But I just wanted to get your thoughts on the market broadly.

Okay. Go ahead, Sheridan.

Colton, this is Sheridan. When we examine the ethane market, it's clear that recovery expectations will likely be volatile throughout the year in certain areas. However, with the rise in domestic demand and increasing international export demand, we still anticipate some growth in ethane demand. Currently, ethane stands as the sole advantage crack in the petrochemicals sector. In the short term, we are experiencing some softness due to ongoing maintenance in the petrochemical industry and they are addressing certain logistic challenges on the supply side. However, our discussions with customers indicate that this situation is improving. This gives us confidence that we will see significant opportunities to extract more incentivized ethane from the Bakken for the remainder of the year.

Yes. Maybe a related question there. Sorry, go ahead.

No, we didn't say anything. Go ahead.

Yes. Just on the optimization of marketing, it looks like that ticked higher here in Q1. I think historically, you all have highlighted the Conway to Belvieu ethane spread as key indicator of optimization opportunities? I guess, one, is that still a good marker? And then, two, can you frame the opportunity that you're seeing if so?

Well, a lot of things that happened in the optimization of marketing between 4Q and 1Q. You remember in 4Q, we were down due to timing of inventory sales, and we said we'd get that back in 2022 when we got it back in the first quarter of '21. And the reason we use ethane as the marker for the Conway to Belvieu spread for optimization is the fact that ethane is the product we have the most of. So that's volume in it. But volatility in that spread gives us a lot of opportunity, whether or not it's going to Belvieu or in favor of Conway with all products. So we were able to use that volatility to make our positions on contracts to make minor adjustments either way if in favor of Conway or in favor of Belvieu; what we need is just some volatility between the two markets, not necessarily just with wide markets to Belvieu.

And I guess in terms of the spread that we've seen just over the course of Q2, I mean, is that maybe offer a little bit of upside relative to that 5% guidance contribution?

Yes. We're seeing a little bit wider spread right now on the ethane side in Q2, and that's mainly right now due to the fact that we have some Mid-Continent crackers that are in turnaround. We think they'll be short-lived through May, but it has given us some upside in the second quarter.

I just wanted to kind of collect some of the comments you guys have had so far. Just thinking about the flat or unchanged guidance versus some of the weather impacts. I guess you've talked about first quarter well connects being a little bit better talked about Mid-Con maybe being a little bit better. But just can you kind of line up the moving pieces that get you to kind of maintained guidance versus after the weather impact, specifically? Is your kind of ethane recovery assumption actually better now than it was a few months ago?

This is Kevin. I think you highlighted several key aspects we are considering. Yes, we've noticed that weather has affected our Bakken volumes, but it has not altered our overall growth outlook for the Bakken this year, both in G&P and NGL. That's a positive sign. Additionally, we are observing activity levels meeting or exceeding our initial guidance expectations, which we believe will help mitigate the impact of the weather. We have identified strong opportunities for ethane recovery both so far this year and looking ahead. You mentioned growth, and we are seeing promising developments from other processors and producers in the Mid-Continent regarding increasing volumes. We believe this presents additional potential. In the Permian, while we haven't focused on it much during this call, we continue to capture a good share of the volume growth from that region, supported by our West Texas LPG and WesTex pipeline systems. There are many favorable factors at play in various areas, including our efforts in optimization and marketing within the NGL business. We believe these will more than compensate for any negative effects we experienced due to severe weather in April.

Maybe just as a follow-up, you guys talked about kind of strong international demand for NGLs. Can you just remind us where you sit on the export idea and kind of what the latest might be?

Well, we continue to work it. As we've said for a while, it's a piece of the business. We would love to extend the value chain, and we see that as a natural extension. It's a nice fee-based business. But at the same time, we're working with a lot of different markets, and we're trying to get a deal done. It would happen, but we're not going to step out and do something that's going to earn a return that we're not used to. So we're going to be disciplined. We're going to be intentional about a dock project, but we continue to work it.

I guess a couple of questions and one kind of follow-up question, I guess, maybe on ethane. On one of your competitors' conference calls earlier this week, there was mention that the Permian is still rejecting about 200 to 200,000 barrels a day of ethane. And obviously, if we hit some bottleneck constraints with natural gas egress in the Permian, then you would look to recover that. So I guess maybe my question is, if this actually does happen and you start going to full ethane recovery mode in the Permian, what do you think that means for ethane recovery and other basins? Do you think that you have to have an offset there? And if so, kind of what basins do you think you'll see some of the offsets?

Yes. I believe that the 200,000 barrels may not all be recoverable in the Permian. I can only comment on our system, which is effectively maximizing ethane recovery. However, if natural gas prices decline, and if there is more ethane available for recovery in the Permian, it will likely exert downward pressure on ethane prices compared to other basins, with the Mid-Continent Basin being the first to experience this. That said, we still have the ability to prioritize Mid-Continent recovery over Permian by adjusting our rates, similar to our approach out of the Bakken. We have consistently maintained that at full rates, Bakken production will be in rejection for this year and in the future. While there may be some influence on ethane recovery, I do not anticipate it will significantly affect our outlook for the Mid-Continent.

The other question is about Bakken egress and the situation over the next two or three years. Do you anticipate any egress bottlenecks for oil, NGLs, or natural gas? If so, which one do you think will be impacted first?

I believe the basin is in excellent condition. Oil is performing well with energy transfer and apple's expansion. They're doing great. We've discussed NGL; we currently have capacity and a quick, low-cost expansion option. We could increase NGL capacity by another 100,000 barrels a day. Regarding residue, there is still volume on Northern Border that can be priced or moved. Bakken gas can replace gas coming from Canada. There is an open season right now for 400 to 500 million a day that Northern Border has on a Bison reversal, and there are also some smaller expansions being considered from a residue perspective that could enhance the basin's residue takeaway. Overall, we feel that the existing capacities and potential expansions position the basin very well for takeaway.

Yes. I just wanted to start off with a couple of clarifications. If I heard correctly, I think you said April volumes reduced by 20% because of the weather events. So just wanted to clarify, is that 20% based on the peak rates that you mentioned hitting in April? Or is it more related to Q1 averages?

Yes, that would be roughly off the 1.4 Bcf a day.

I would like to know if the runway you mentioned for exceeding 400 well connects in Bakken refers to the exit rate, or if you believe the total for the full year could likely surpass 400 well connects.

I believe Sheridan mentioned that we are still keeping our guidance range, with the midpoint being 400. Connecting over 90 wells in the first quarter is a great start to the year, so we think there may be potential for some upside.

And then one on CapEx trend. So it seems like you expedited the start-up date on the MB-5 a little bit, and then you're also adding gas capacity. What does that mean for the total CapEx for full year? I saw that Q1 was a little bit higher or was it pickup from Q4?

Yes. We are still confident in our capital guidance range. Looking at the first quarter, we typically experience some seasonal timing adjustments related to routine growth. We did not raise the costs for MB-5 in order to accelerate that schedule; it was simply our capability to move things forward thanks to favorable scheduling in the early stages of the project. Therefore, our capital guidance range remains unchanged.

I have a question for clarification regarding the various components of the average bundled rate for the Rocky Mountain NGL raw feed throughput. If you averaged $0.26 for the $3.14 in the first quarter and reached $3.85 in April, what would the similar average bundled rate be if a significant amount of incentive ethane corresponded to the $3.85?

Theresa, this is Sheridan. To be honest with you, I have no idea what it will be. It will be around the 26. The reason I say that is the accountants will work through it and we have a lot of moving parts on that. But it's going to be 26% to 27% in that range is where I would say that it's going to come out to be.

And to the earlier comment about your customers seeing some alleviation downstream on the pet chem front, I'm just curious to hear how do you see the pace and path of supply chain models relieving out of the Gulf Coast? To the extent that it can reduce some of the economic run cuts on ethane cracking and increased demand.

Well, I could say is as we've talked to our customers and seeing what they're seeing in there, and they said they have had some issues getting rid of the polyethylene pellets to get them exported out of there or actually get them from the petrochemical facilities to the dock. And they keep saying they're working through that and continue to improve that to be better. And they're optimistic that it's going to improve over time is kind of what we're hearing. Obviously, if there's a bottleneck there, you could see them slow down their production to make sure they get rid of the products. But they seem to be more upbeat now than they have in the past.

And lastly, if I can just squeeze one more in. On the cost side, you've seen some good cost control in the first quarter. Just wondering your outlook for costs for the year as far as potential inflationary pressures go?

We've observed some inflationary pressures. However, we believe the escalators in our contracts will more than compensate for the cost increases we've experienced. Typically, operational costs in the first quarter are a bit lower compared to the rest of the year. Despite that, we remain optimistic. All of this has been considered as we reaffirm our guidance, which takes inflationary pressures into account.