Oneok Inc (OKE) — Q3 2022 Earnings Call Transcript

Thank you, and welcome to ONEOK's Third Quarter 2022 Earnings Call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. After our prepared remarks, management will be available to take your questions. Statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer.

Thanks, Andrew. Good morning, everyone, and thank you for joining us on our call this morning. We appreciate your interest and investment in our company. On the call today is Walt Hulse, the 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, our Senior Vice President of Natural Gas Liquids and Natural Gas Gathering and Processing; and Chuck Kelley, our Senior Vice President of Natural Gas Pipelines. Yesterday, we announced strong third quarter 2022 earnings, affirmed our 2022 financial guidance midpoints, and provided our 2023 growth outlook to exceed $4 billion of adjusted EBITDA. Our third quarter results demonstrate the resiliency of our strategic and integrated assets in some of the most highly productive U.S. shale basins, and our employees have dedicated themselves to the safety, reliability, and sustainability of our operations. Looking forward, we expect continued strength in producer activity and increased volumes and higher earnings from our fee-based services across all our business segments in a favorable commodity price and increasing demand backdrop. So with that, I will turn the call over to Walt for a discussion of our financial performance and our insurance update.

Thank you, Pierce. ONEOK's third quarter 2022 net income totaled $432 million or $0.96 per share, a 10% increase compared with the third quarter of 2021 and a 4% increase when compared with the second quarter. Third quarter adjusted EBITDA was $902 million, a 4% year-over-year increase and an increase from the second quarter. Higher results benefited from increased Rocky Mountain region NGL and natural gas volumes, higher realized commodity prices, net of hedging, and higher average fee rates. Additionally, we had lower interest expense due to our lower debt balances and increased capitalized interest. Third quarter 2022 results reflected our $5 million property insurance deductible related to the Medford incident and approximately $30 million of losses related to the 45-day business interruption waiting period under the terms of our insurance policy. We received notice in September that our Medford property insurers agreed to pay $100 million unallocated first installment of insurance proceeds. As of today, we received $45 million of that amount and expect to receive the remaining amount before year-end. We've applied this cash receipt to our outstanding insurance receivables. After the waiting period ended, we incurred costs subsequent to the 45-day business interruption waiting period of $21.7 million, primarily related to third-party fractionation agreements and recorded a partial impairment charge of $6.7 million, representing the value associated with certain Medford facility property based on the limited assessments completed to date. There are no income statement impacts of these incurred business interruption costs or impairment charges as they are fully offset by insurance receivables. We continue to share information with our insurance carriers to refine ongoing business interruption insurance coverage and to determine the ultimate path to replacement of this temporary loss of fractionation capacity. We will provide additional updates as we move forward in this process when material information is available. Lastly, for the third quarter, we ended with higher NGL inventory levels that have since been sold forward, and we will realize a $17 million earnings benefit from those sales in the fourth quarter and first quarter of 2023. As of September 30, our net debt-to-EBITDA on an annualized run rate basis was 3.8x, and we continue to view 3.5x or lower as our long-term aspirational goal. We currently have no long-term debt maturities until September of 2023 and we have no material exposure to floating interest rates through our current outstanding long-term debt. Yesterday, we affirmed our 2022 guidance midpoints of $1.69 billion for net income and $3.62 billion for adjusted EBITDA. We now expect total capital expenditures of $1.2 billion, driven by our acceleration of spending on the MB-5 fractionator and smaller-scale expansion projects that were not previously planned for '22 across our three business segments that will contribute to growth in 2023. Key drivers for our 2023 outlook of more than a 10% increase compared with our 2022 midpoints to exceed $4 billion in adjusted EBITDA include continued strength in fee-based earnings and rates, stable to growing producer activity providing higher natural gas and natural gas liquids volumes in our system, and expected higher realized commodity prices due to higher hedges. These tailwinds into 2023 from our base business, additional insurance recoveries related to Medford, and our strong financial position provide us confidence in our double-digit earnings growth outlook for next year. I'll now turn the call over to Kevin for a commercial update.

Thank you, Walt. Let's start with our Natural Gas Liquids segment. Rocky Mountain region NGL volumes increased 17% year-over-year and 12% compared with the second quarter 2022, driven by volume recovery following the April severe weather and overall volume growth, including higher incentivized ethane on our system. Volumes have remained strong in the region with September averaging more than 380,000 barrels per day. Third quarter Mid-Continent NGL volumes decreased year-over-year and compared with the second quarter, due primarily to lower ethane recovery on our system. In the Permian Basin, NGL volumes were unchanged year-over-year and compared with the prior quarter. With the recent third-party plant connection in October, we expect volumes from this region to increase through the remainder of this year and into 2023. We also continue to see interest from customers seeking additional NGL takeaway out of the Permian, so we will continue to evaluate future low-cost expansions on our system. From a 2022 NGL volume guidance perspective, we expect to be near the midpoint of our guidance range, due mostly to the ethane rejection we have been seeing in the Mid-Continent and the impact of the April storms. Regarding ethane, beginning in September, we started to see lower demand for ethane from the petrochemicals leading to more ethane rejection across most regions. The decrease in utilization has been driven by lower NGL demand globally, especially in China and Europe, along with some petrochemical outages. We expect ethane demand to remain somewhat muted in the fourth quarter and into early 2023, and this has been factored into our 2022 and 2023 expectations. As we sit today, we are seeing ethane and ethylene inventories starting to get worked off, which we believe will lead to increasing demand in 2023. For ONEOK, it is typical that we don't incentivize as much ethane out of the Bakken during the winter season due to higher natural gas prices and natural gas demand, but we will continue to be opportunistic. As it relates to our 2023 outlook, we expect the Permian to be in full ethane recovery, the Mid-Continent to be in partial recovery and the Rockies continuing to provide opportunities to incentivize recovery. Construction continues on our 125,000 barrel per day MB-5 fractionator in Mont Belvieu, which we still expect to be completed early in the second quarter of 2023 and is reflected in our updated 2022 capital guidance. Moving on to the Natural Gas Gathering and Processing segment. Producer activity remained strong in the Rocky Mountain region with third quarter processed volumes averaging 1.4 billion cubic feet per day, a record quarter for us. Our average fee rate also increased, reflecting the impact of contract escalators, higher volumes on higher fee component contracts, and a larger percentage of our total volumes from the Rockies. On a go-forward basis, we expect this average rate to range between $1.10 and $1.20. Year-to-date, we have connected 244 wells in the region. We now expect to complete approximately 375 well connections near or at the low end of our guidance due to the impact of the April storms, as well as the timing of some wells coming on and the availability of completion crews and materials. Activity still remains high, just some timing elements that we now expect will push a few large pad completions into next year. These same factors also led us to adjust our volume expectations for 2022 to be near or slightly below the guidance range. There are currently more than 40 rigs and 18 completion crews operating in the basin, with more than 20 rigs and approximately half the completion crews on our dedicated acreage. As we've said before, approximately 15 rigs on our acreage are needed to maintain natural gas production at current levels. But with more than 20 currently on our acreage, we expect to see higher well connections and volumes in 2023 compared with 2022. The 200 million cubic feet per day Demicks Lake III processing plant under construction remains on schedule to be completed in the first quarter and will bring needed capacity to the region. The basin-wide DUC inventory remained stable at around 500, considering the increasing rig count and activity with half of those on our dedicated acreage. In the Mid-Continent region, we continue to see increased activity with four rigs now operating on our acreage and more than 50 rigs basin-wide. We expect steady to increasing activity and volumes through the remainder of the year and into next year, with the majority of rigs basin-wide driving additional NGLs to our system. In the Natural Gas Pipeline segment, with strong year-to-date results benefiting from the continued increasing demand for natural gas storage and transportation services, we now expect this segment to exceed the high end of its guidance range of $400 million to $430 million. We are highly subscribed for our storage service in Oklahoma and Texas at higher rates and for longer terms, including our recent expansion of our Texas storage facilities, which is now fully subscribed through 2032. Additionally, we are expanding 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 April 2023 and is nearly 90% subscribed through 2029, and we are also evaluating an additional expansion of our Texas storage assets. Lastly, before I turn the call back to Pierce, we began a compression electrification project on our interstate Viking Gas Transmission pipeline to improve operational reliability and provide future greenhouse gas emissions reductions on the system. The project is expected to cost $95 million and be completed in the third quarter of 2023 and is included in our outlook. Pierce, that concludes my remarks.

Thank you, Walt and Kevin. As we enter the last couple of months of 2022 and look forward to the next year, I'm proud of our employees and want to thank them for their hard work and contributions. They continue to focus on operating safely, sustainably, and in an environmentally responsible manner, which is key to our success as a midstream operator. How we operate is important, but also how we engage with our employees, communities, and other stakeholders is equally as important. In addition, for ONEOK, it is crucial to remain focused on meeting the growing energy demand for today, even as we look forward to helping drive the energy transformation needs for the future. We also recently announced that ONEOK joined with two other large publicly traded companies based in Oklahoma and a venture capital firm to fund an effort to transform Oklahoma into a hub of energy technology start-ups and redefine a sector that has shaped the region's economy for more than a century. We believe this partnership aligns with our long-term business strategy, which includes potential low-carbon investments that contribute to long-term growth and business diversification. ONEOK has been building the right teams and resources to better participate in the innovative practices and technologies that we see now and those that may play a role in the future. Before I turn the call over for Q&A, I wanted to highlight an important ESG item we mentioned in our earnings release. ONEOK's MSCI ESG rating was recently reviewed and updated by MSCI to AAA from AA, and we maintained our status as an industry leader. Our ESG efforts are a source of pride for ONEOK, and we are committed to continuing to make progress in these important areas. With that, operator, we're now ready for questions.

Maybe to revisit some of the assumptions in your prepared remarks around 2023 earnings growth, it seems like we should see some tailwinds on volumes and hedges rolling higher. I was curious if you could just dive a little bit further into the ethane recovery assumptions for 2023. Historically, you guys have been pretty conservative on this assumption, but I’m curious how we should think about how Btu concerns plateauing ethane demand for the next few years and Permian natural gas tightness impacted some of your assumptions related to Rockies recovery into 2023 and that 10% earnings growth?

Brian, this is Kevin. I'll start and then Sheridan can add in. Think about the overall 2023 growth outlook. We expect our volumes are going to be up, both NGL and Gathering and Processing in all of our basins with the tailwinds, reflecting the existing rigs we're seeing today as those carry over into 2023. So volume growth is going to be the primary driver. We're also expecting a full year of the contract fee escalations, so we'll see a full year of that. Additionally, you're going to see a step-up in our hedging. If you look at the hedge prices we have in 2023 compared to 2022, that's going to represent a significant step up there. The ethane recovery assumptions are pretty similar to what we had going into 2022. As we mentioned, we expect full recovery out of Permian, partial in the Mid-Continent, and we’ll continue to incentivize ethane out of the Bakken where appropriate.

The one thing I would add on that is when we look at 2023 as we did in 2022, we have limited incentivized ethane coming out of the Bakken factored in. We really see that as an opportunity going forward.

Great. I appreciate that color. Maybe just to pivot towards capital allocation for a minute. ONEOK is trending towards its leverage target and payout ratio targets. Obviously, there are some concerns that were partially alleviated with earnings around the insurance proceeds. But I was curious about how we should think about the return of capital framework looking into 2023, given that you've had the same dividend since 2019, but at the same time, you’ve never cut it. So any color there, I appreciate it.

So Brian, this is Pierce. With our positive earnings growth indications for 2023, our payout ratio and our debt-to-EBITDA metrics are indicating that we are going to have more flexibility to execute on one or more of the capital allocation levers that are available to us to create value for our shareholders as we progress through 2023. So that's the way I'd answer your question there.

I wanted to ask the latest on Northern Border. Where does it stand in terms of gas coming from Canada versus the Bakken? Is there any more room there? And then related to that, any updates on a potential expansion project on Northern Border?

Yes, Michael, it's Kevin. For your first question, we estimate there's still probably 300 million to 400 million a day of gas coming from Canada. That will continue to get displaced from Bakken as Bakken grows. So you've got some opportunities there. We're also in active discussions with multiple parties on various residue takeaway and demand projects, including some demand projects in Basin. We have secured about 100 million a day of takeaway solutions going south that don’t go to Northern Border. So that’s going to help. We don’t think there's one single solution that provides that, but we believe we’ll be able to find the necessary capacity out of Basin as we move forward.

Okay. I guess my second question is just wanted to ask — I know you haven't really made a decision yet about whether you're going to rebuild Medford, or maybe build something else at Mont Belvieu or otherwise. So just curious if you could talk to the dynamics. If you choose not to rebuild Medford, does that change anything in terms of the market dynamics between Conway and Mont Belvieu for you as it relates to Sterling?

No. I mean, there will be a little bit of an impact on that if we build down in Mont Belvieu if you put it down there. But today, when Medford was operational, most of our liquids were transported down Sterling to the Mont Belvieu market anyway. So we think overall, the market dynamics are not going to be impacted that much, whether we build it at Medford or at Mont Belvieu.

In the third quarter, there was more ethane recovered from the Rockies and less from the Mid-Con than I would have expected. Is it fair to say that most of the time you would recover marginal ethane from the Mid-Con before the Rockies, and that maybe it was specifically due to AECO price blowouts in the quarter that it was a little flipped from usual?

Yes. We look at the gas basis as really what drives us regarding which basin we're going to incentivize. So yes, AECO pricing versus what's going on in the Mid-Continent will drive where we incentivize ethane coming out of there. We did see a lot of benefit in the third quarter coming out of the Rockies due to the basis and what we could secure gas prices for ethane. We see that as a great opportunity in these two basins, and we can incentivize at times and play that gas base between the two. So we think that's a big advantage to our system.

Okay. That's helpful. Assuming that Bakken does go back to higher rejection in the next couple of quarters, I think the Northern Border Btu spec at that receipt point is probably going to exceed the 1,100, which I think Northern Border has said is the max they really want. Does anything happen then? Or is that just all kind of a whole FERC process to a potential cap in?

Jean Ann, this is Kevin. Yes, as you reject more ethane, that will raise the Btu content on Northern Border. If we were back to where we were pre-COVID, that number was north of 1,100. Right now, we understand there's no spec on the pipe. Northern Border will watch it. They have some levers to pull if it gets too high, and downstream markets start to raise concerns. They continue to work with shippers and all relevant stakeholders to potentially go back to FERC for a spec, but we don’t have an exact timing on that. So we'll watch it. If it gets to the point where the Btu level gets too high and downstream markets start raising issues, then we have the option to recover ethane to lower it back. If we do that, it would be required at full rates, not incentivized rates.

This is Steve McGee on for Jeremy. Just starting along the insurance line, as far as business interruption insurance goes, just trying to get an idea of what's covered under that. Does that include optimization, marketing in there as well? And then for 2023, does that include the business insurance as well?

Well, as we said on the last call, the coverage that we have is that we are entitled to receive coverage to get us back to what we would have made, but for this event. So it's system-wide. If that does impact other parts of the business, like optimization and marketing, that gets factored into our business interruption calculation. The money that we received in September was not necessarily deemed a run rate because there are still some moving parts that we're working with the insurance companies to refine how we look at business interruption going forward. Those costs were predominantly the third-party frac costs. As we work with them and refine how much optimization in the market, we do expect to receive some benefit from that going forward. In 2023, we expect business interruption coverage to continue, and at that point, we hope to be on a pretty regular month-to-month catch-up so that we don't foresee any real variation from the business interruption insurance going forward.

Understood. And then, I guess, flipping over to CapEx, you pulled some forward well connects kind of towards the lower end of the guide but still up a little bit this year. So I'm guessing most of the uptick this year is MB-5. Should we expect a little bit less CapEx into 2023 now because of that? Can you walk us through that raise this year and then what that looks like in the next year as well?

Yes, Steve, it's Kevin. Yes, MB-5 was a significant contributor, moving some of that capital forward into 2022. We also had a compressor station up north in the Bakken that we've moved forward with that will add to our growth in 2023. We referenced the Viking compression project in our opening remarks, and then we just had a handful of smaller routine growth-type projects that typically have extremely strong earnings power from them, which will contribute in 2023. A combination of these factors led to the increase in capital expenditures in 2022. You are thinking about 2023 correctly; once we complete MB-5 and Demicks Lake III, you would probably expect a little step down in capital barring other projects that we continue to work on that could prove beneficial. That’s the unknown at this point; we are constantly working on new projects and will announce them as they reach Final Investment Decision.

First, I would love to touch on the 2023 guidance and delve into some of the assumptions here. Mainly, if you could provide some color on your price deck assumption and in terms of Bakken activity, in particular, any color you can share on assumptions for rig counts, well completions, exit-to-exit growth in oil or gas? And then granted that the ethane recovery dynamic remains in development and can be volatile, but any sort of color you can give on the recovery assumption in 2023 versus the level that you just reported for the third quarter 2022?

Theresa, this is Kevin. We're not going to get into the detailed guidance specifics that we'll release probably sometime early next year. But I would tell you, as we think about price decks and activity levels, there's probably more rig activity in the basins than we currently reflect in our outlook. So, today’s activity levels are strong enough to help us achieve that exceeding $4 billion figure.

Got it. And in the Gathering and Processing segment, that $1.16 average fee rate is quite a step-up from the previous run rate, and I understand the color you shared on the fee escalators and the composition of it. Just trying to think about the trajectory of growth here. Was there anything in particular driving this? And as we think about the escalators in 2023 and beyond, should we assume similar magnitudes of step-ups or generally speaking, how should we think about this line?

Theresa, this is Sheridan. When you think about that margin that's driving that increased step up, a lot of it came from escalation. We also saw some influence from contract mix. We got volume on higher contracts or more margin contracts compared to others. The major factor driving us going into 2023 will depend on inflationary escalators, so we will have to see how inflation comes out and how it compares to CPI. This impact of CPI in 2023 versus 2022 will be a significant driver on where we land on that moving forward.

I wanted to first focus on the Natural Gas Liquids optimization and marketing number, I think you all noted a 44 million decrease sequentially. Was any of that a result of Medford at all, or was it just other factors? I believe you mentioned some price differentials and timing on the NGLs?

Michael, this is Sheridan. Yes, Medford did have an impact on those numbers, and that's reflected there. During that 45-day waiting period, we took some hits in optimization and marketing. Additionally, spreads were a little narrowed during that time. We had forward sales due to Medford that we pushed forward, and we will receive some of those proceeds, or $17 million, in the fourth quarter and first quarter as we move forward. These factors contributed to the drop in optimization and marketing.

Okay. Just to clarify, do you expect to recover insurance proceeds if there are any reductions in marketing optimization? What would that look like?

We do. We expect to receive insurance proceeds for losses in marketing and optimization that we would have received if Medford had been operational. However, much of the $45 million comes from that 45-day waiting period, which we wouldn’t get because that’s on us. But going forward, we expect coverage for any losses related to marketing and optimization.

Okay. That's helpful. And then previously, you all have given a current month run rate out of the Bakken for NGL takeaway. I think you gave a September number. Any indication you can provide on what October looks like going forward?

Michael, we're not going to provide numbers for Q4. We gave you the number for September, which was a strong run rate. As we move into the fourth quarter, we have to consider potential weather factors, hence, we’re holding back on specifics.

Okay. Understood. And then lastly, if I break up the insurance proceeds from one allocation for business interruption, and the other for property loss, are you viewing the property loss as replacement cost? Or are you considering it as getting back the frac capacity to where like MB-5 recover some of that? Just trying to think of how that shapes out from the way you and the insurance company are thinking about it?

We have specific coverage that would cover the replacement or the repair of the facility to get it back to where we would achieve the 210,000 barrels of capacity that we had. We have property coverage to return us to the same position we were before. We do have the flexibility to decide where to allocate those dollars, and that's what we’re still considering at this point. Moving forward, we would expect to likely not receive as much unallocated money; rather, it should be allocated out for business interruption on a monthly basis once we get into a routine.

Would MB-5, since it was already undergoing construction, be something that you could allocate any sort of property loss to? Or would it be in MB-6 and beyond if you wanted to?

No. MB-5 is its own stand-alone project that we built due to our necessity. It will help us a bit as it comes online, and we are entering our natural ramp-up phase. However, the proceeds we received for the repair or replacement of the Medford facility will remain discrete, and they will cover those costs.

Thank you all. Our quiet period for the fourth quarter starts when we close our books in January and extends until we release earnings in late February. We'll provide details for that conference call at a later date. Have a good day, and thank you for joining us.