Oneok Inc (OKE) — Q3 2021 Earnings Call Transcript

Thank you, Todd, and welcome to ONEOK third quarter 2021 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, we'll be available to take your questions. Statements made during this call that might include one of expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision of the Securities Acts of 1933-1934. 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. Just a reminder, before we turn it over to the conference coordinator for Q&A, we ask you to limit yourself to one question and one follow-up in order to fit in as many of you as we can. With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer. Pierce?

Thanks, Andrew. And good morning, everyone. We appreciate your interest and investment in ONEOK. And thank you for taking your time to join us today. With me on today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Strategy and Corporate Affairs, and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas Liquids, and Charles Kelly, Senior Vice President, Natural Gas. Yesterday we announced strong third quarter earnings results and increased our 2021 financial guidance expectations. Our third quarter results were driven by NGL and Natural Gas volume growth on our system, the result of increasing producer activity and improving market demand. As world economics continue to recover from the pandemic, we're seeing demand continue to recover for natural gas and NGLs. And we're focused on helping to meet that increasing demand for these critical energy products, particularly as we head into the winter months. As we look forward, we continue to coordinate with our customers on future growth expectations and are focused on innovation throughout the Company. In September, we announced a greenhouse gas emissions reduction target, marking another major environmental milestone for our Company. Our goal is to achieve an absolute 30% reduction, or 2.2 million metric tons of our combined Scope 1 and 2 emissions by 2030, compared with 2019 levels. We will undertake a number of strategic emission reduction measures to meet this target, including the further electrification of certain natural gas compression assets, implementing additional methane mitigation through best management practices, system optimization in collaborating with our utility providers to increase the use of low carbon energy for our operations, just to name a few. As we continue to evaluate low carbon opportunities, we remain focused on those that will complement our operations and capabilities while providing long-term stakeholder value. As we have additional details on specific projects or future emission reduction activities, we will share that information and our progress toward our 2030 target. I will turn the call over to Walt Hulse to discuss our financial performance.

Thank you, Pierce. With yesterday's earnings announcement, we once again increased our 2021 financial guidance expectations and narrowed our ranges. We now expect net income of $1.43 billion to $1.55 billion and adjusted EBITDA of $3.325 billion to $3.425 billion with a midpoint of $3.375 billion. This represents a 10% increase in our net income and EPS guidance midpoints and a 5% increase in our adjusted EBITDA midpoint compared with our previous guidance. Our higher expectations are driven by continued volume strength in the Rocky Mountain region and Permian Basin, increased demand for natural gas storage and transportation, and higher commodity prices. Our 2021 capital expenditures are expected to be closer to the higher end of our guidance range of $525 million to $675 million as a result of increased producer activity and project timing. We continually work with our customers to evaluate their future capacity needs and supply expectations, and we'll align our projects and capital investment with those needs. Our outlook for growth in 2022 continues to strengthen, driven by increasing producer activity and rising gas-to-oil ratio in the Williston Basin, along with the recent completion of our Bear Creek plant expansion. Additionally, new ethane demand from new and expanding petrochemical facilities is expected to come online before the end of the year. Kevin will provide more detail on each of these shortly. Now for a brief overview of our third quarter performance. For the third quarter 2021, net income totaled $392 million or $0.88 per share, a 26% increase compared with the third quarter 2020, and a 15% increase compared with the prior quarter. Third-quarter adjusted EBITDA totaled $865 million, a 16% increase year-over-year and an 8% increase compared with the second quarter of 2021. Our September 30 net debt to EBITDA on an annualized run-rate basis was 4.0 times, and we have line of sight to be below 4 times in the near future. We ended the third quarter with no borrowings outstanding on our $2.5 billion credit facility and nearly $225 million of cash on the balance sheet. We continue to proactively manage our balance sheet and upcoming debt maturities. Earlier this week, we redeemed the remaining $536 million of senior notes due February 2022. Our next debt maturity is not until October of 2022. In October, the Board of Directors declared a dividend of $0.93.5 or $3.74 per share on an annualized basis, unchanged from the previous quarter. I will now turn the call over to Kevin for an operational update.

Thank you, Walt. In our Natural Gas Liquids segment, total NGL raw feed throughput volumes increased 5% compared with the second quarter of 2021 and 10% year-over-year, averaging nearly 1.3 million barrels per day, our highest NGL volume to-date. Third quarter raw feed throughput from the Rocky Mountain region increased 5% compared with the second quarter of 2021 and nearly 50% compared with the third quarter of 2020. Volume growth was driven by increased producer activity in the region, ethane recovery, and increasing volumes from recently connected third-party plants, including a 250 million cubic feet per day third-party plant that came online in July. Throughput volumes from the Mid-Continent and the Permian Basin also increased. Permian volumes increased 12% compared with the second quarter of 2021, driven by higher ethane recovery and producer activity levels. We also connected an additional third-party plant in the Basin during the quarter. The segment was also able to utilize our integrated assets to capture the benefit of location and commodity price differentials during the third quarter, providing additional earnings on top of our primarily fee-based results. Petrochemical demand continues to strengthen as facilities have returned to normal operations following Hurricane Ida and as the pandemic recovery continues. New petrochemical plants coming online before the end of the year could provide more than 160,000 barrels per day of additional ethane demand once fully operational. This additional capacity, combined with strong ethane exports, should support a wider ethane to natural gas differential in 2022. Ethane volumes on our system in the Rocky Mountain region increased compared with the second quarter of 2021, as we incentivized additional ethane recovery during the third quarter. Recovery continued in October and is also expected throughout November, given current regional natural gas and ethane prices. In other regions, we continue to forecast partial ethane recovery in the Mid-Continent and near full recovery in the Permian for the remainder of the year. All of these assumptions are included in our increased financial guidance for 2021. Any additional ethane recovered would provide upside to our 2021 expectations. Discretionary ethane on our system is now more than 225 thousand barrels per day. Of that total opportunity, more than 125 thousand barrels per day are available in the Rocky Mountain region and 100 thousand barrels per day in the Mid-Continent. As NGL volumes continue to grow across our systems, so does the discretionary ethane. Moving on to the Natural Gas Gathering and Processing segment. In the Rocky Mountain region, third quarter processed volumes averaged nearly 1.3 billion cubic feet per day, a 2% increase compared with the second quarter of 2021 and nearly 25% increase year-over-year. Scheduled plant maintenance at four of our processing facilities, which have since come back online, decreased third quarter volumes by approximately 30 million cubic feet per day for the quarter. We estimate that approximately 14 to 15 rigs, which can drill approximately 300 wells per year, is enough to maintain 1.4 billion cubic feet per day of production behind our system. Any additional rigs combined with the rising gas-to-oil ratios of wells already connected to our system would provide additional volume growth. Conversations with our producers in the region continue to point to higher activity levels through the end of the year and into 2022. There are currently 32 rigs and 10 completion crews operating in the basin, with 17 rigs and 5 completion crews on our dedicated acreage. This is more than enough activity to grow gas production on our acreage. In addition to the rigs currently operating in the Basin, there remains a large inventory of drilled but uncompleted wells, with more than 520 basin-wide and approximately 300 on our dedicated acreage, compared with about 400 ducks on our dedicated acreage at this time last year. In the third quarter, we connected 72 wells in the Rocky Mountain region, and in October, we connected more than 30 additional wells. Based on the most recent producer completion schedules, we still expect to connect more than 300 wells this year. With our Bear Creek plant expansion and related compressor stations now complete and in-service, we should see a significant number of well completions in the fourth quarter in Dunn County as producers have time to time their completions with the startup of our expansion to avoid flaring. The new plant will accommodate increasing volumes as it ramps to full capacity over the next 2 to 3 years. With Bear Creek 2's completion, we now have approximately 1.7 billion cubic feet per day of processing capacity in the Basin. We continue to see increased activity in the Mid-Continent region with 2 rigs now operating on our acreage and ten wells connected during the third quarter. Sustained higher natural gas and NGL prices will drive a continued increase in activity next year. During the third quarter, the gathering and processing segment's fee rate averaged $1.02 per MMBtu compared with $0.94 per MMBtu in the third quarter of 2020. Changes in our average fee rates continued to be driven by our volume and contract mix each quarter. We still expect the fee rate for 2021 to average between $1 and $1.05 per MMBtu. Under the natural gas pipeline segment, this segment is stable; fee-based earnings continue to drive solid results with adjusted EBITDA increasing 8% compared with the prior quarter. As we entered the winter heating season, we continue to see increased interest from customers for additional long-term transportation and storage capacity on our system following the extreme winter weather event earlier this year. The segment's market-connected pipelines and more than 52 billion cubic feet of natural gas storage provide critical services to customers year-round but especially during the winter. As always, we're working with our customers to understand their needs and to help meet increasing demand in the coming months. Pierce, that concludes my remarks.

Thank you, Kevin. The strong results for this quarter underscore the quality of our assets and the hard work and dedication of our more than 2,800 employees. I'm very proud of the fact that our employees remain disciplined and focused on the importance of safety, reliability, and the responsible operations of our assets. The first nine months of this year have set up well for the end of the next year, with Company-wide earnings growth in 2021, and have laid the foundation for continued growth next year. With that, Operator, we're now ready for questions.

Hi, good morning, everyone. Maybe to start off, I was wondering if we could talk about tailwinds into 2022. You gave some pretty good color about well completions in the presentation there. It sounds like you've got 100 wells left to complete for this year out of 300 with only 2 months to go. You've got Bear Creek now in service. Is it also fair to assume that you've potentially have some PPI inflators on some of your assets, like Bear Creek and so forth? And so just wondering how to think about ONEOK as we head into 2022. In the past, you've talked about a $3.5 billion to $4 billion upside potential. Is that the case? Are these tailwinds stronger now? Just wondering if you can give us some color as to how you think of the tailwinds right now, as we head into 2022.

Sure. This is Kevin. I think there are several aspects to that question. As we look ahead to 2022, I'm particularly focused on the activity levels we're observing in the Bakken with the rigs, the inventory of drilled but uncompleted wells, and the increasing gas-to-oil ratios. We're also experiencing significant volume growth in the Permian, which I consider core volume growth. Additionally, as I mentioned earlier, there is increasing ethane demand within the system, which may lead to higher ethane recovery as we approach 2022. That's where I see the positive factors. Regarding your inquiry about inflators in our contracts, in our NGL and G&P segments, the vast majority of our contracts include escalators on the fee rates. Therefore, we are well-positioned to address inflation and similar concerns, so those contracts are secured.

Okay. You're still good with the range from before? Okay. And maybe just given their leverage trajectory curious about what kind of return of capital actions or potentially considering when you hit your leverage targets mid-next year. Could we potentially see a dividend increase or buybacks on the table? Just need color on that as well too, please.

Sure, Shneur. This is Walt. We are very pleased to have achieved that 4.0 here in the third quarter. We want to continue to see that trend lower, and so we're not going to stop looking for that debt reduction and then improving debt to EBITDA ratio. The other thing with free cash flow is it gives us the opportunity to invest in our capital growth as we go forward, utilizing free cash flow and not having to finance. Obviously, as we get further and further along into the reduction, our options open up. But at the moment, we're focused on debt reduction and using our free cash flow for high-return projects.

Great, perfect. Thank you very much. Appreciate the comment today.

Great.

Thank you.

Good morning. I'd like to start with the ethane extraction incentives on the backend. This quarter had some disruptions due to several plants being offline, making it difficult to assess the sequential performance. Can you provide insight into the quarter-over-quarter increase in your ethane incentives? Additionally, the Bellevue spread over Ventura Gas doesn't seem sufficient to encourage ethane extraction. Should we consider this related to your exposure to ACO? While I understand you won't disclose the specifics of your ACO exposure, could you share your limitations and constraints so we can better estimate your maximum exposure?

When we evaluate the opportunity to incentivize ethane, we focus on the gas prices at our gas plant rather than at Ventura. We consider the current market conditions and what the market is offering us for gas at the plant before making a purchase. If we decide to encourage ethane extraction, we acquire it at that price or at a slightly better rate. Therefore, it's essential to look at what's happening at the gas plant rather than relying on Ventura or ACO. Regarding the volume, we did incentivize more ethane in the third quarter compared to the second quarter. While we're not providing specific numbers on the increase, it is confirmed that we did incentivize more in the third quarter.

And would it be safe to assume that you could incentivize even more on a fiscal basis going forward?

Yes. Especially as volumes grow in the basin and grow on our G&P segment, we do have an opportunity to incentivize more ethane. But as I said in previous, we look at what's going on in the marketplace, whether the prices are an all basis, to see how much we think is the right amount of ethane to bring out. So we don't push other basins that we have operations into rejection.

Okay. And then I guess when we think about the ethane demand that is ready to ramp up, how do you guys think about the risk to the operational crackers not running at full utilization if gas prices and ethane prices get too high?

What I would say there is still a very strong spread between ethane and ethylene. And so it looks like the crackers have plenty of room to continue to run. Now with the new crackers running at full rate, we think they will, but they need to run it more. Ethane needs to be cracked today than has been because of that wide ethane to ethylene spreads. So we see good volume going forward. And then you couple that with the exports that are coming online, we expect stronger export demand in 2022 than we've seen in 2021, especially as additional crackers come on in China.

Great. Thank you.

I think on prior calls, you talked about a low double-digit increase for EBITDA versus what a midpoint of $3.2 billion of EBITDA at that point in time with the guidance. And I'm just wondering if that's a fair way to think about it? Commodity prices look like they're higher than what was quoted in the first call there. But just trying to update, I guess how you guys are thinking about 2022 now versus what you had laid out in the first quarter.

Jeremy, this is Walt. I think when we laid it out in the first quarter, our guidance at that point was $3.050. Obviously, with the strength that we've seen build throughout the year, we already achieved what was out there at that point in time. What I would comment on is that quarter-to-quarter, we have seen everything strengthen in our business, whether it be producer activity, commodity prices. So all of the trends are headed in the right direction. We think that we're going into '22 with very good tailwinds, and we will give you our '22 guidance in February.

Got it. That makes sense there. And maybe just pivoting towards DC for a minute, and granted, it's a pretty uncertain outlook there; we have a very cloudy crystal ball. But just wondering if you could offer any thoughts on what you might be looking for out there and how that could impact one of the higher 45Q, or a minimum tax, or anything else that is on your mind at this point?

Well, the rest of the alternative minimum tax and there's still quite a few moving parts right now. If it is enacted, it's unclear at this point how it will interplay with bonus depreciation, which is in place for the next several years and has been in place. It's unclear how it will interplay with the interest limitations that are already in place on the NOL utilization. And also the billion-dollar threshold may be increasing, making the whole conversation somewhat irrelevant. So we're on top of it. We've got a team that is watching the developments there, and we will continue to do that. But at the end of the day, even in its worst case, we wouldn't see it changing our progress on deleveraging or being able to fund our capex going forward.

Got it. Thank you for that. That's a very helpful answer.

Hi. Good morning. North Dakota statewide clearing increased in recent months, as you show on page 8. Can you talk about the reasons for that? And if it's an indicator that it might be tough to get all of the expected gas production growth going forward? Notably, ONEOK's acreage clearing hasn't increased, so maybe it's different for you all look processing capacity, but just wondering about the trends in wider North Dakota versus yours.

Jean Ann, this is Kevin. I'll chime in as well, but I think what you saw going on through the summer is you had several outages at facilities. We've talked about some of the facilities we had down, and while the majority of the cases producers are then curtailing that volume, sometimes you'll see a little tick up in flaring. And the same with some of the third-party plants that were going through some expansions and other maintenance activities during the summer. I don't think that's a trend. I think it's going to trend back the other way as we get into what I'd consider more normal operational run rates for these facilities. The conversations we're having with all our customers up there, and I'm sure third-parties are the same way. The target discussion is zero. It's not the state targets anymore. So we are working with our customers for sure on how we drive that number as close to zero as we possibly can, as it relates to the timing of our facilities, as it relates to how they're bringing on large pads, etc. I would expect that to turn around as we get these facilities up and going.

That's really helpful. Thank you. I am also curious if there has been any recent progress on either the Indiscernible or the Northern Border Expansion to increase gas takeaway options.

Yes Jean. And this is Chuck. The projects that were discussed prior to the pandemic when we saw the trajectory of the basin requiring additional residue takeaway, we are revisiting those projects as we see increased activity in the Basin, rising GORs. There's quite a few factors that indicate that in the next, call it two to three years, these projects are going to become necessary. So there's a lot of work being done on that behind the scenes right now, and we will definitely be part of that solution.

Great. Thanks. That's all for me.

Thanks. Good morning, everyone. I wanted to just ask a bit about the Mid-Continent. I just want to hear what you're seeing in terms of producers' plans there. Do you think there's a possibility that Mid-Con volumes could be flat in 2022, if there's been enough uptick in drilling activity? Thanks.

Michael, it's Kevin. If you consider the overall Basin, it's encouraging to see the increase in rigs. Several producers have announced notable boosts in production in the Mid-Continent, particularly from a gas and NGL standpoint. Our perspective is that we prioritize the total number of rigs since our NGL connections span nearly every plant in the basin. Therefore, when a rig operates in the Mid-Continent, the NGLs are likely to be directed to us, which benefits us. Although we might not have many rigs actively on our dedicated acreage in G&P, we do have a few. We have completed some wells, which is positive. We are actively engaging with our customers, and if current price levels are maintained, we could see increased activity in the Mid-Continent.

Great. Thank you very much.

Good morning, sir. Maybe, then I point the 2 questions there on ethane incentive and then the Mid-Con, I think we saw a slight recovery in the average bundled Mid-Con rate for Q3. Was that really just a result of this spread between OTT and Bellevue widening out a bit? And if so, I guess, are current levels or Q3 levels at least sufficient to get that historical $0.09 per gallon rate.

This is Sheridan. I want to point out two factors that contributed to the increase in the average CNF fee in the Mid-Continent. One was the wider spread between OG2 and Bellevue ethane, and there was a month during the quarter when we didn't need to offer any incentives for ethane; it occurred naturally. Additionally, we experienced an increase in our C3 plus volume, which commands a higher rate than the ethane volume. Many of our plants utilize a split tier rate for ethane and C3 plus, so both of these factors played a role in the higher rate.

Great. And then back on the balance sheet, you've highlighted the desire to drop below 4X, looks like effectively there on a run-rate basis. Is there a new leverage target that you guys think about whether it's a ratio or do you think more in terms of an absolute debt target? I'm really just interested in how you're thinking about the balance sheet over the next couple of years.

Well, I mean, we've said before that aspirationally we'd like to head towards 3.5 and maybe even a little bit lower, but I think we're going to see opportunities going forward. The EBITDA levels that we're at, there's a whole lot of money to invest. So we think we've got meaningful room there to continue to invest in great projects and still see our deleveraging trend downwards towards that aspirational target of around 3.5 times.

Thank you.

Hi, good morning, guys. Just a quick one on capital. Clearly, you guys have shown the Elk Creek Slide before. Obviously, there's plenty of capital efficient optionality there on the downstream side. But can you frame for us maybe generally the capex dynamic in 2022 versus 2021? Certainly a very modest capital year with Bear Creek, but with additional third-party plant online in the second half, GOR trends, and that pent-up volumes dynamic you mentioned in anticipation of Bear Creek. Can you just frame for us what capital could look like in G&P or more broadly in 2022?

Tristan, this is Kevin. I won't provide a specific number at this time since we'll share guidance early next year. Our approach to capital involves continuously assessing our customers' needs alongside our available capacities. This includes evaluating processing and gathering needs in areas like Bakken and Bellevue, as well as pipeline requirements in West Texas. We're gathering all relevant information from our customers regarding their plans for the upcoming year and incorporating that into our strategy. As you noted, we have a solid position with Elk Creek, and if we require additional frac capacity, such as for MB-5 to restart that paused project, we've already invested a sizable amount of the necessary funds. We're in a favorable situation because the extra capital needed for that capacity, along with the timeframes for delivery, are manageable. We might only need about 12 to 18 months to complete a frac. For our pipelines, we've already ordered and purchased the required materials, so we aren't exposed there. Therefore, these potential projects are well-positioned; they won't require a large expenditure, and we can execute them fairly quickly.

Good morning. So we're talking about 25 a month in well connects in the Bakken. Obviously, it's increasing. I think you said 30 in October, and if I did the math right, we may be at 38 or more for November and December. So I had a couple of questions. 1. If these trends continue, is the same inevitable that by year-end, next year, we hit over 1.5 billion cubic feet a day? And this is all just off your activity, right? On your acreage. But ignores activity with third-party processing plant connections into your NGL system, right? How much more upside could there be there?

You've mentioned the favorable conditions we've previously discussed. If the rig count exceeds 30 in the Basin, we definitely think that's sufficient to increase gas production throughout the area. This will not only be beneficial from a gathering and processing perspective, but also for all the third-party connections that Sheridan has on the NGL side, where we expect to see growth as well. We're well positioned because we still have approximately 125,000 barrels a day of capacity available on Elk Creek and our NGL systems coming from the Basin. Therefore, we won't need to invest significantly to realize that EBITDA.

Okay. And it sounds like this is great tailwinds, everything is looking wonderful. I understand we'll wait till February to get next year's guidance, but it seems like updated full-year midpoint EBITDA guidance kind of suggests decent but kind of silver fourth quarter, nothing like more recent outperformance versus expectations. Could you maybe talk about the gives and takes going into the fourth quarter?

Well, I think the gives and takes are as you're probably going to predict saying is we always know there's weather we have to deal with in North Dakota. And so if you get a calm early winter, then yeah, I think that could provide some upside. We do have a lot of well connects forecasted in the last couple of months of the year, and that's what producers are telling us. But if you get some weather, could those be delayed? Potentially, but I think the key is we have this arbitrary cutoffs at December 31. Well, the well connects are going to get done whether it's in on December 15 or January 15. So as we think if we back up and look at the trends over the next several months, clearly we've got optimism about where we're going to be. But I think, yes, you've hit on there. I think there's some upside as well with both volumes if these wells come online like we think and as well as the ethane recovery option that would be a positive upside for us in the fourth quarter.

Thank you.

Hey, good morning. Two questions: first is just thinking about the ethane recovery opportunity and going into next year and maybe putting into context with your view of a widening spread between ethane and natural gas next year just with increased demand. So it'd be fair to think that there is a double opportunity there between both volumes and maybe an ability to reduce the incentive pricing that you have on ethane?

Yes, this is Sheridan. You're exactly right. We think there's an opportunity both. And obviously, if we had the wider the ethane to natural gas spread gets, the more we can capture of that spread. And so the incentive is less. And also as volume continues to increase in the Bakken and potentially in the mid-continent, we also have the opportunity to bring even more ethane out. So you're thinking about it right. There's a double benefit going into 2022.

Great, thanks. And then just maybe a follow-up on thinking about, I guess, the maintenance gas level at the very least on 300 wells a year, and the 14 or 15 rigs. Does that also imply or assume any continued work-down of the DUC inventory or is that 14 to 15 rigs enough to keep volumes where they are? And then whatever else agreeing with the GOR but not have to really dive into the inventory of the DUCs anymore.

I think you'll see the DUC inventory continue to decrease gradually. These changes will likely happen at the same time. With 10 completion crews and the number of rigs running, I believe you'll be able to reduce the inventory. It might take a bit longer, but having more rigs will help get down to a manageable inventory level where producers prefer not to have a completion crew waiting for a well to be completed. I expect it to stabilize, but I anticipate a period over the next several months where both the DUC inventory will be reduced and new wells will continue to be produced by the new rigs.

Great. Thanks very much.

Thank you for taking my question. Mine is focused on the long-term. When do you anticipate revisiting your capital allocation strategy, especially considering what the industry has experienced in recent years? How do you view the best way to return capital to equity holders? Do you see this primarily as increasing dividends, or do you lean more towards share buybacks with minimal dividend growth? Will special dividends be a consideration? I'm interested in understanding how you and the board are approaching capital allocation as you expect fundamentals to improve.

This is Pierce. I believe our main focus is to increase our earnings per share and enhance value through our equity price. As Walt mentioned earlier, as we move down to 4 and possibly reach 3.5 or lower, new opportunities arise for us. However, we are also assessing which growth opportunities we can reinvest into the business to sustain our earnings per share growth. This will allow the board to consider additional opportunities. Walt, do you have anything to add?

No, I think that's exactly right. As we see our earnings grow, the Board will continue to evaluate all opportunities related to that. We have more attractive returns and high multiple projects that we want to focus our capital on. If that is not the case, then we will need to consider other ways to return capital to shareholders.

Got it. Thank you guys. I'll follow up offline, much appreciated.

Welcome. Thank you.

Our quiet period for the fourth quarter and year-end starts when we close our books in January of 2022 and extends until we release earnings in late February. We'll provide details for that conference call at a later date. Thank you all for joining us, and the IR team will be available throughout the day. Thank you.