Oneok Inc (OKE) — Q1 2021 Earnings Call Transcript

Thank you, Andrew. Good morning and thank you all for joining us today. As always, we appreciate your continued trust and investment in ONEOK. Joining 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 Chuck Kelley, Senior Vice President, Natural Gas. ONEOK's solid first quarter results are providing positive momentum as we enter warmer operating months. Volumes on our system and our outlook for the year continue to improve, supporting the increase to our financial guidance, which we announced yesterday. Even without the weather-related earnings impact in the first quarter, our base business earnings increased compared with the fourth quarter. But while the quarter's results were positive, winter storm Uri did provide us with significant operational challenges that I want to highlight. Our employees' preparation before the extreme weather event and hard work during it enabled us to operate with very few interruptions. Operations teams ensured our assets were weatherized for extreme conditions and that our employees were on-site and prepared to make the necessary adjustments to keep our assets running. Many of our employees were faced with challenges of their own, including limited or no heat, running water, or electricity at their own homes, but still worked to help ONEOK provide essential natural gas and NGLs when needed most. Despite these extraordinary winter weather conditions, we continued to meet the critical needs of our customers, including natural gas utilities and electric power plants. Our natural gas pipeline and storage assets were particularly well-positioned to address the needs for natural gas. The segment's ability to continue providing reliable service helps meet increased natural gas demand and contributed to higher adjusted EBITDA during the quarter. Kevin will provide more details in a moment. Despite weather-related volume impacts across our operations, strength in our base business was evident in our Rocky Mountain region NGL and natural gas volumes during the quarter. The Williston Basin continues to outperform expectations and provide us with solid and stable earnings. As I've said before, ONEOK's earnings growth in 2021 is not dependent on increased rig activity or increasing commodity prices. The opportunities available to us are from a robust drilled, but uncompleted well inventory, increased natural gas capture, and rising gas to oil ratios in the Williston Basin and increasing ethane demand. The opportunity for earnings growth without the need for significant investment is unique to ONEOK and our strategic assets in key operating areas. With yesterday's earnings announcement, we raised expectations for 2021 and now expect adjusted EBITDA growth of more than 17% compared with 2020. Our higher guidance expectations include the latest producer forecasts and drilling plans, and our earnings range also includes the potential impact from a shutdown of the Dakota Access Pipeline. Increasing producer activity, higher commodity prices, and strengthening energy markets have further enhanced our view of 2021 and are setting up to provide positive momentum as we exit the year. As we look toward 2022, high single to low double-digit growth in EBITDA appears reasonable in the $50 to $70 per barrel price range when you adjust 2021 for the approximately $90 million weather impact to revised guidance. We also continue to look for opportunities outside of our traditional growth drivers to enhance our businesses. Our sustainability and renewables teams continue to actively research opportunities that will complement our extensive midstream assets and expertise. They're focusing on opportunities to lower our greenhouse gas emissions while enhancing profitability, further strengthening the vital role we expect to play in a low-carbon economy. Opportunities under evaluation include the further electrification of compression assets, potential carbon capture and storage projects, sourcing renewable energy for operations and other longer-term investments such as hydrogen transportation and storage. And as always, we'll remain disciplined in our capital approach as we develop these opportunities. Demand for the products we transport remains strong. The pandemic and recent weather events have further highlighted the importance of natural gas, NGLs, and the many end-use products they help create, which all play a vital role in helping us lead safer and healthier lives. Our ability to transport these products safely and responsibly to markets is key to their ultimate end use. This quarter once again proved our ability to do that even in the most extreme conditions. With that, I will turn the call over to Walt to discuss our financial performance and updated 2021 guidance.

Thank you, Terry. With yesterday's earnings announcement, we increased our 2021 net income and earnings per share guidance by 10% and adjusted EBITDA guidance by 5% compared with our original expectations provided in late February. We now expect a net income midpoint of $1.35 billion or $3.02 per share and an adjusted EBITDA midpoint of $3.2 billion this year. At the segment level, we increased 2021 adjusted EBITDA guidance for the natural gas gathering and processing and natural gas pipeline segments, primarily due to increasing producer activity from higher commodity prices and incorporating the results of the first quarter. Adjusted EBITDA guidance for the natural gas liquids segment decreased slightly, primarily due to reduced volumes and lower ethane demand in the first quarter related to Winter Storm Uri. Total capital expenditures for 2021, including growth and maintenance capital, remain unchanged from our original expectations of $525 million to $675 million, a more than 70% decrease compared with 2020. This range includes capital to complete the Bear Creek plant expansion and associated field infrastructure in the fourth quarter of this year and a low-cost expansion of the Arbuckle II pipeline in the second quarter. Now a brief overview of our first-quarter financial performance. ONEOK's first quarter 2021 net income totaled $386 million or $0.86 per share. First-quarter adjusted EBITDA totaled $866 million, a 24% increase year-over-year and a 17% increase compared with the fourth quarter of 2020. Distributable cash flow was more than $660 million in the first quarter, a 27% increase year-over-year and a 28% increase compared with the fourth quarter of 2020. First-quarter dividend coverage was nearly 1.6 times and we generated more than $245 million of distributable cash flow in excess of dividends paid during the quarter. Our March 31 net debt to EBITDA on an annualized run rate basis was 3.98 times compared with 4.6 times at the end of 2020. We ended the first quarter with no borrowings on our $2.5 billion credit facility and more than $400 million of cash. Earlier this month, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis, unchanged from the previous quarter. Healthy earnings in the first quarter provided momentum for 2021 and helped to accelerate our deleveraging efforts. As Terry mentioned, increasing producer activity, ample capacity on our systems, and the continued opportunity for flared gas capture and strong gas to oil ratios in the Williston Basin and increasing ethane demand continue to support our base business and increase financial expectations this year. I'll now turn the call over to Kevin for a closer look at our operations.

Thank you, Walt. Winter Storm Uri impacted operations across all three of our business segments in February. Reduced volumes due to well freeze-offs, especially in the Mid-Continent and Gulf Coast Permian regions, increased electricity costs and customer facility outages presented challenges during the quarter. However, our ability to meet increased demand for natural gas and NGLs during the period helped to more than offset the volume impacts. Volumes across our operations returned quickly following the extreme weather with NGL raw feed throughput and natural gas processing volumes in the Rocky Mountain region in March, exceeding our first quarter 2021 averages. Let's take a closer look at each of our businesses, starting with the Natural Gas Pipelines segment. The safe and reliable operations of our pipeline and storage assets through the storm provided critical transportation services and storage withdrawals for our customers. In addition, we sold 5.2 Bcf of natural gas, which we previously held in inventory into the market in the first quarter of 2021 to help meet the increased demand. This compares with 1.2 Bcf that we sold in the first quarter of 2020. Our ability to provide reliable service throughout the extreme weather conditions highlights the importance of market-connected pipelines and storage assets and the value of these vital services. Since the storm, we've received increased interest from customers seeking additional long-term transportation and storage capacity on our system. This morning we initiated an open season for more than one Bcf of incremental firm storage capacity at our West Texas storage assets. In our Natural Gas Liquids segment, first-quarter 2021 earnings increased compared with the fourth quarter of 2020, despite the volume impact from Winter Storm Uri. System-wide volumes were reduced by an average of approximately 64,000 barrels per day during the quarter with the largest impacts in the Mid-Continent and Gulf Coast Permian regions. During the first quarter, increased optimization and marketing activities in the segment related primarily to higher commodity prices and wider spreads between Conway and Mont Belvieu prices presented opportunities to utilize our integrated NGL pipeline and storage assets to meet market needs, helping to partially offset volume and cost-related impacts. First quarter raw feed throughput from the Rocky Mountain region increased 4% compared with the fourth quarter of 2020 and 20% year-over-year, despite an 11,000 barrel per day impact from Winter Storm Uri. As we sit today, volumes from the region have reached more than 300,000 barrels per day. During the quarter, ethane volumes on our system in the Rocky Mountain region increased compared with the fourth quarter 2020 as we incentivized some ethane recovery, which we have talked about in the past. On a short-term basis, we were able to incentivize recovery by purchasing ethane at several gas plants at a premium value to natural gas, selling it into the Mont Belvieu ethane market and collecting the difference while increasing producer netbacks and NGL volumes on our system. Continued ethane recovery from the region will depend on regional natural gas and ethane pricing and is not included in our updated guidance. Economics in the Mid-Continent region also provided the opportunity to incentivize ethane recovery, and we continue to expect partial recovery in the region throughout the remainder of the year, which is included in our guidance. In the Permian Basin, we saw increased ethane rejection in the first quarter. Overall, petrochemical facility outages related to Winter Storm Uri reduced demand for ethane during the quarter. We expect ethane recovery in the Permian Basin to continue ramping back up, as petrochemical demand returns following February storm impacts, with a return to near full recovery in the second half of 2021. Discretionary ethane that can be recovered on our system in both the Mid-Continent and Rocky Mountain regions remains approximately 100,000 barrels per day. In the Rockies region, full recovery would provide an opportunity for $400 million in annual adjusted EBITDA at full rates. Our opportunity for recovery in either region at any given time will fluctuate based on regional natural gas pricing, ethane economics, and potential incentivized recovery. Moving on to the natural gas gathering and processing segment. In the Rocky Mountain region, first quarter processed volumes increased 5% year-over-year, despite colder-than-normal weather in February. In March, volumes exceeded 1.2 billion cubic feet per day, a level we can maintain even without increased producer activity. Our ability to capture additional flared gas, rising gas to oil ratios, and a large inventory of drilled, but uncompleted wells on our acreage are the key drivers of our 2021 volume expectations. Recent producer M&A activity in the Williston Basin has highlighted new drilling plans on acreage that in some cases may not have been developed in the near term, but now likely will be. And indications from several of our producers in the basin point to increasing activity in the second half of 2021, particularly in Dunn County. In response to this, we've resumed construction on our Bear Creek processing plant expansion and expect it to be complete in the fourth quarter of this year. Once complete, we will have approximately 1.7 Bcf per day of processing capacity in the basin, and we'll be able to grow our volumes with minimal capital as producer activity levels increase. In the first quarter, we connected 38 wells in the Rocky Mountain region and expect to connect more than 300 this year. Based on very recent producers' completion schedules, we expect a significant increase in well connects in the second and third quarters, as completion activity picks up with improved weather. There are currently 16 rigs operating in the basin, with eight on our dedicated acreage, and there continues to be a large inventory of drilled but uncompleted wells with more than 650 basin-wide and approximately 350 on our dedicated acreage. With eight completion crews currently operating in the basin, no additional activity or crews are needed to hold natural gas production flat on our acreage or reach our well connect guidance for the year. Any additional completion crews would present upside to our guidance. As the current DUC inventory gets worked down, we expect producers to bring rigs back to the basin to replenish the inventory levels, providing tailwinds as we move into 2022. Additionally, as of February, approximately 100 million cubic feet per day of natural gas flaring remained on our dedicated acreage, presenting a continued opportunity for us to bring this volume onto our system and help further reduce flaring in the basin. The gathering and processing segment's average fee rate remained $1.04 per MMBtu during the quarter, unchanged from the fourth quarter 2020. Winter Storm Uri reduced Mid-Continent volumes by approximately 30 million cubic feet per day for the quarter, causing the average fee rate mix to shift more towards the Rocky Mountain volumes, driving the higher average rate. We now expect the fee rate for 2021 to average close to the high end of our $0.95 to $1 per MMBtu guidance range. The segment's 2021 guidance does not assume increasing producer activity levels in the Mid-Continent region or the Powder River Basin. However, both areas have received attention, as commodity prices have strengthened. Any increasing activity in those areas would be an added tailwind to our 2021 expectations and provide volume momentum into 2022. Terry, that concludes my remarks.

Thanks Kevin. Good overview of a challenging, but encouraging quarter that has positioned us well for the rest of 2021. With volumes trending upward and strength in our base business, our outlook continues to improve. But we remain disciplined in our approach and focus on what matters most for the long-term sustainability of our business. Enhancing our financial stability, participating in the innovation necessary for a transition to a low-carbon economy and serving our customers' needs safely and responsibly continue to be our focus. The first quarter showcased many of these focus areas and we have many more great things to look forward to in the remainder of this year and beyond. Thank you to our employees for all that you have done this quarter and over the past year to focus on customer needs and continue operating safely and responsibly. Operator, we are now ready for questions.

Thanks. Good morning, everyone.

Good morning, Michael.

I have a couple of questions. First, the T&F rate out of the Bakken decreased by $0.01 compared to last quarter, falling from $0.28 to $0.27. I would like to know if this change is related to the ethane recovery incentivization program, or if there are other factors we should consider.

Michael, this is Sheridan. You're right. The tick down in the average rate was due to the amount of ethane that we incentivized to come out of the Bakken and the lower rate that was received for those barrels.

Great. And then second question, I apologize if I missed this, how many rigs are running on your acreage today in the Bakken?

Michael, this is Chuck. We've got eight of the 16 rigs in the basin on our acreage today.

Great. Thank you very much.

Hey, good morning guys. This is James on for Jeremy. Maybe just wanted to start here on the Bakken outlook. You mentioned the 350 DUCs on the acreage and the unchanged G&P completion guidance here. So maybe just looking out into where you see the DUC inventory by year-end? And also just cadence for completion activity in the remainder of the year, you mentioned 2Q and 3Q you expect to see a ramp, but is it safe to kind of assume with only 38 wells completed in the first quarter maybe an average out for the remaining quarters here to meet the well completion guide?

This is Kevin here, James. Yes, absolutely. As we mentioned in our remarks, we expect a significant increase in completions. Chuck and his team are having discussions with producers that are just a few days old or a couple of weeks old. We anticipate a notable increase in Q2 and Q3. Q4 typically depends a bit on the weather, but we remain confident about our guidance of 300. So yes, we expect to see a pickup in the summer.

And James, this is Chuck. What I would add to what Kevin said is, we completed the 38 in Q1 but a lot of that planning was done back in Q4 and a lot of the producers still had some uncertainty over stability of crude pricing, regarding what was DAPL going to do. So we didn't anticipate Q1 would be strong. But as Kevin said, the ramp is extremely good starting here in Q2, we're already seeing it and certainly into Q3 and these are recent conversations.

Sounds good. I appreciate the information. ESG is certainly a relevant topic with emissions being discussed these days. Looking at your natural gas pipeline operations, have you explored opportunities to reduce carbon emissions? What is the status of that project? Have you allocated a specific budget for it yet, or are you still in the preliminary stages?

Yes, James, this is Terry. So certainly, we have remained very focused over the years and in particular in the last couple of years on reducing our emissions impact across our asset footprint, not just in natural gas, but in liquids as well. And so that remains a key focus for us. The types of things that we're looking at that can be big needle movers in terms of reducing our greenhouse gas emissions, things like electrification of compression, natural gas-fired compression being converted to electrics, which then can consume or be in a position to consume renewable power. That's a key focus. We have done some of that. We've got a lot of electric compression operating today, particularly in the Williston Basin. But we also have some big units down in Oklahoma. So we know how to do it and we expect to continue to steadily increase our fleet of electric compression. So that's a key focus. And obviously, the renewables team is working on a lot of other things on the energy transition front, taking advantage of our skill set and taking advantage of the pipeline processing capability or expertise that we have. So that's kind of it in a nutshell. Kevin, anything you can add to that?

No.

I guess as far as capital, yes, we have allocated some capital not just on the compression front, but also we're doing some work on the carbon sequestration front as well. So we've allocated some meaningful capital there. It's not a huge amount of capital as we're just getting started in this. But as we move forward, we expect that capital to pick up. I think the key emphasis is that projects that we work on or that we're considering in the sustainable area of sustainability they’ve got to make economic sense. They've got to generate a reasonable return.

Got it. That makes sense. I appreciate that. Just last one for me if I can sneak one in. Do you guys have a number you can share or just color you can share on where you see gas/oil ratios trending post 2021? I know, you mentioned higher, but is there any more detail you can share there?

No. I think I should review the trends we've observed over the past four years, which have been around 70 percent. We have no reason to expect that this will decline.

Yes, it's increased over 15% just here in the past year. You can see that in our chart.

Got it. Thanks for your questions. I will leave it there.

Thanks, James.

Hi. Good morning, everyone. Thank you for taking our questions today. Terry, I wanted to focus on some of your prepared remarks about the momentum building towards the end of the year. You mentioned that 2022 could see growth in the high single digits or low double digits, which seems to suggest around $3.4 billion. Could you elaborate on the momentum a bit? In your earlier responses, you discussed the completions towards the end of the year. I understand the cadence in relation to 2021, but how have your discussions with producers shifted now that oil has been in the 60s for a while? Has there been an evolution since February? Is some of the momentum coming from that, or is it mainly linked to gas and NGL recoveries?

Well, Shneur, Kevin in his remarks, he mentions momentum. He uses that word. Because he used that word I'm going to let him answer that question.

Thanks, Terry. No, Shneur, it's everything you mentioned. Our discussions with customers extend beyond just our G&P clients, as Sheridan and his team engage with customers across all basins, and we expect to see an uptick in activity. We've noticed prices stabilizing at a favorable level, which clearly can yield excellent returns in nearly every basin we're operating in. The increasing gas to oil ratio in the Bakken boosts our confidence that we'll continue to see those volumes rise. There are many factors contributing to this. A key point from our discussions with producers, especially in the Bakken, is that while there's been much talk about the rig counts, they will first focus on reducing their DUC inventory. Once that inventory decreases and production normalizes, we anticipate that rig counts will return based on our dialogues with them. This is why we believe that in the latter half of the year, you will see an increase, particularly in rigs rather than completion crews, setting the stage for momentum as we approach 2022.

I would like to add to Kevin's comments by noting that as we observe the global recovery from the pandemic, it is certainly giving us a significant boost. This is evident not only in the relatively strong commodity prices but also in the demand for petchem. Although the petchem sector in the Gulf Coast experienced challenges due to weather, we have seen a recovery and those operations are returning to normal. Furthermore, new petrochemical plants are being constructed worldwide. Demand for petchem is showing no signs of slowing down, which is a key aspect of our strategy and will continue to be crucial as we look toward 2022 and beyond.

I appreciate the information you provided. Could you elaborate on the topic discussed in the prepared remarks regarding ethane recovery in the Rocky Mountains? You mentioned purchasing at a premium and selling in Mont Belvieu, and it seems this potential isn’t reflected in your current guidance. Can you explain this further? I understand you’re offering incentives, so it might be less than the $400 million you mentioned as potential upside, but is this a daily decision? Are you also entering into smaller-term contracts for three, six, nine, or twelve months? I'm curious to know if this is managed on a day-to-day basis or if there could be momentum with smaller-term contract deals.

Shneur, this is Sheridan. We are doing this day-to-day to be able to capture the most spread between the markets. So we saw that in February, where the price of gas spiked really high then we shut down the incentive program and did not buy ethane during that period of time. So it really is a day-to-day decision that we can make. So we're looking at both the regional gas price in the Bakken and the price of ethane in Mont Belvieu to make those decisions. And we didn't bring out the whole 100,000. We only brought out a small portion of ethane during this period of time.

Okay. Are any of the producers interested in doing some smaller term deals at all? Or is this just going to continue to be a day-to-day decision?

Right now, we believe it's more effective for us to operate on a daily basis. This approach allows us to capture the full spread between the gas price at which we buy and the price at which we sell ethane. If we were to commit to a longer-term deal, we would have to lock in that spread, and we expect that spread to continue widening. Therefore, we prefer to manage it on a day-to-day basis for now.

All right. Perfect. Thank you very much guys. Really appreciate the color today.

Thank you.

Thank you. I wanted to also discuss the comments from 2022. Can you provide any further insights on the different basins? Specifically, what are your thoughts on growth in the Bakken compared to the Mid-Con and Permian? I'm curious about how these regions will perform in 2022, especially since you mentioned that you don't expect increased activity in the Mid-Con based on the 2021 results, particularly in a price range of $50 to $70.

We're not going to provide a lot more detail at this point since it's still an outlook. However, we're quite optimistic about the Bakken and expect growth there. We have a strong position in the Permian, where we've seen an increase in activity as well. On the other hand, we don't foresee significant growth in the Mid-Continent basin.

Okay. And then I wanted to also touch upon Bear Creek. I know in your prepared remarks you talked about Dunn County seeing a lot of activity. And I know there have been some big wells there. And I know that you have a plant there but is that full already? Or are the producers currently flaring the gas there or building a DUC inventory? I just wasn't sure if you were able to move those volumes to be processed at your other plants in McKenzie if necessary?

No. Christine, this is Kevin. We’ve talked about that plan. When we built the first one there, that was geographically more isolated than our other facilities. So we have a small amount of ability to move gas around to other plants. But effectively that plant is near full at this point. But producers are working closely with us to align their timing to the timing of when our infrastructure not just the plant but also some of the field infrastructure necessary to gather the gas to get it to the plant. So we've mentioned the four large producers down there in Continental in Marathon in ConocoPhillips and XTO, large acreage positions and they are coordinating with us extremely closely on the timing so that we don't flare gas down there.

So should we expect like kind of a stair-step, in volumes when that plant comes on? Or is it still going to be more of a slow ramp?

I think the way a lot of the developments occurring nowadays is it will be a little lumpy, I mean as they bring on pads. But yes, you're not going to see some massive step change the day the plant comes up. Because again, producers we all are extremely concerned and want to reduce flaring as much as possible. And so the coordination among us and our customers is very tight on the timing of when the capacity will be available.

Hey, morning guys. Two questions for you on CapEx, first one just thinking about Bear Creek II being official now. I think that was already contemplated in the original CapEx range. So just curious, does that sort of push you up towards the higher end of the range? And if not, what are the drivers that would actually get you to that high point?

Spiro, this is Kevin. Yes. The Bear Creek facility and the related field infrastructure is included in that forecast. The things that would get you to the higher end is really more activity. I mean if you look at that CapEx, you've got our maintenance cap which is pretty static. And then, the rest of it is Bear Creek II and routine growth, which are things like well connects and some small projects in the other segments. And so to the extent, we see increased activity and that comes sooner. And we would need some more kind of that standard high-return well connect capital. That's what would take you towards the higher end. The rest of it is just going to be timing as far as how the capital is spent over the course of the year.

Got it. That's helpful. Sticking with CapEx it sounds like a lot of the growth you guys are contemplating in 2022 won't require CapEx. It sounds like very much a continuation of a lot of the trends you're seeing in 2021. So I guess, as we think about the trajectory into next year for CapEx, is it fair to assume more or less in line with 2021 if not maybe even below these levels?

Yes. The key thing to me about our capital spend as we look forward is the available capacity or the operating leverage we have across our assets. We referenced in our remarks about the capacity we'll have in the Bakken from a processing perspective. We recently completed an expansion on Elk Creek to bring it up to 300,000 barrels a day. And we've still got the legacy Bakken NGL line, combined with OPPL that we could always use. We talked about the minor expansion on Arbuckle II. We've got capacity in West Texas. So we can grow our EBITDA without a significant uptick in capital. So yes, you're probably going to think of it more in lines of 2021, if you're talking about 2022 more in line of that versus we're not going to have to add another long-haul pipeline or something like that.

I think that's a valid point, Kevin. Spiro, please bear with me for a moment. This leads into an important observation regarding our available excess capacity. Our infrastructure is well-positioned to support operations over the next few years without the need for significant new transmission projects in the NGL sector. In a favorable pricing environment, we could see our EBITDA approach $4 billion without requiring substantial capital investment. This illustrates the concept of headroom or available capacity that we are trying to communicate to the market. We have already built a substantial portion of the necessary infrastructure, and our future growth will primarily involve smaller, routine expansions. Therefore, under the right pricing conditions and activity levels, we could potentially achieve a $4 billion EBITDA.

Okay, appreciate those comments Terry. Thanks Kevin.

Good morning, everyone. I appreciate all the insights on completion activity and your thoughts for 2022. Considering the acceleration in well connects throughout the year, should we anticipate that 2022 will see well connects significantly exceeding the 300 mark you mentioned for 2021? You also mentioned the possibility of rig additions. Could we expect to see rig additions as early as the second half of the year, or is this more likely to happen as we approach the end of the year based on your discussions?

Tristan, this is Chuck. I would say that the rig activity we expect will begin to be noticeable toward the end of spring and the start of summer. It’s definitely more of a second half activity. As Kevin mentioned earlier, our producers have indicated that they will first address their DUC inventory before bringing in the rigs as they typically do around midyear and then increase that activity. We currently have a positive sign with a rise in completion crews in the basin, going from two to eight. Considering the completion crews and the well connections we foresee for the remainder of the year, we are quite optimistic about exceeding the 300 well mark. Looking ahead to next year, we don’t expect anything less. While we won’t dive into specifics for 2022, we anticipate strong momentum carrying into this year and the next.

That's helpful. And then just a clarification question. Kevin, I wanted to go to your $400 million in EBITDA comment with respect to ethane. Is that sort of the potential opportunity in a full rejection to full recovery scenario? Or is that sort of where you're at today moving to full recovery?

We previously mentioned that each additional 25,000 barrels per day of volume from the Rockies contributes about $100 million to EBITDA. Therefore, if we consider 100,000 barrels per day of ethane coming online at full capacity, that would translate to $400 million in annual EBITDA.

Okay, great. Super helpful. Thank you guys very much. Appreciate it.

You bet.

Hi, good morning. I have two questions that may actually be the same question. But the first one is about on slide 10, it looks like February flaring ticked up a bit from the declining trend that we had seen in prior months. Was that a one-off due to weather or some other reason? Or does it suggest that we're hitting a gas constraint somewhere and that flaring could creep up more?

Yes, Jean Ann, this is Chuck. That increase was mostly due to weather and some challenging drilling conditions in certain areas, but it doesn't suggest that we will see an increase in flaring in the basin.

Okay. Cool. Then I guess my questions are different. My second question was also about the incented ethane from the first quarter. Was that that there were sort of some temporary gas blowouts in the basin or something more structural like gas basis is like gradually widening there? It's hard to tell because northern border kind of takes some from the Bakken and some from Canada. But is this sort of the fact that now it's in the money for you to do and before it wasn't suggest something structural is changing in terms of gas takeaway getting limited?

Jean-Ann, this is Sheridan. No, I don't think it has anything to do with gas limited takeaway. What has to do with is we're seeing strength in ethane demand on the Gulf Coast and we saw a spread between gas in the Bakken and ethane prices on the Gulf Coast that we want to take advantage of. And we continue to see that grow especially now as we head into May, we're seeing a lot of increased demand for ethane in the Gulf Coast from our assets down there, probably as strong as we've seen in the last three or four years going into May.

Perfect. That's all for me. Thanks.

Good morning. Congratulations on the good quarter.

Thanks, Craig.

Trying to understand better the roughly 10% year-over-year 2022 EBITDA uplift outlook. If I understand correctly, the 2021 updated guidance includes up to $50 million of headwind on adaptable shutdown. What if anything are you incorporating into 2022 when you say maybe roughly 10% uplift for DAPL? And then if I understand correctly the answer to Tristan's question, while you're assuming a recovery in rig counts to fill in the DUCs, there is no assumption in your 2022 outlook for an increasing frac crew deployment. Is that correct?

I believe there are a few key points to consider. Regarding DAPL, we've discussed its impact before, which we currently assess to be minimal. Given the time that's passed this year and the fact that the pipeline continues to operate without a clear resolution, we remain optimistic. The Environmental Impact Statement is expected to be completed by March 2022. Even if the pipeline were to shut down, we don't anticipate a significant impact for 2022, as there is a strong belief that the permitting process will be resolved favorably. As for rig counts, we've previously indicated that we do expect to see an increase in rigs and activity levels during the second half of this year. However, the specific details of what that will look like moving into 2022 are still uncertain, which is why we've provided a range.

And Craig, we wouldn't have said it if we didn't have visibility to it. You know us too well.

Absolutely. I'm trying to clarify if you anticipate at least around 300 well connections next year, which seems to imply an assumption of a healthy increase in frac crews and rig counts to address the DUCs. Yes, but if we add another two or three frac crews, that could influence your expectations. Is that correct?

Yes.

Great. And one other question. Can you elaborate on prospects for realized Permian pricing to ramp with increasing bundled NGL services?

Craig, could you repeat that? We didn't get it here.

Just your Permian realized NGL pricing is lower because there's still a lot of legacy just transport only, and trying to get a sense for the outlook of being able to switch to more and more integrated services that will give a higher bundled rate.

This is Sheridan. I would say that I don't see a significant increase in the average rate. We are facing a lot of pressure on rates for new volume in the Permian, which is affecting that. Our legacy volumes will remain stable since they are under long-term contracts. However, as we introduce new volumes, they will likely come in at a lower rate. Therefore, I don't expect much of an increase in the average rate on the West Texas system.

What about the ability to combine the transport on West Texas with fractionation to get higher all-in pricing?

Well, right now we've seen sometimes there's been some new rates done, that is basically at our average rate today for both transportation and fractionation.

Really. Okay. Thank you very much.

Yes. Hi. Good morning, guys. And thanks for all the color. My first question was related to your comments previously regarding how you're looking at clean energy investments. I think you referred that you're going to hold those projects to same kind of economic returns. Now most of the recent projects you did on NGL pipelines, et cetera, were more like 4x to 5x EBITDA multiples. So I was just curious when you think about these new investments risk versus reward, how should we be kind of thinking about any incremental investments in that area, especially if you look at CCS and all those kinds of technologies?

This is Kevin. As Terry mentioned earlier, we will uphold our financial discipline and return standards while evaluating these projects. This does not imply that they will meet the four times multiple like some of our previous projects. However, we do expect them to generate a reasonable return. Therefore, if we are investing capital, we will be seeking returns on that investment.

Understood. Any clarity on timeline on those decisions on those evaluations?

Our team is working hard. There are many opportunities available, and we are assessing how they align with our strengths and our needs. We will not rush this process. It's important to us, and while we are dedicated to it, we will not move forward just to have a project. We want to ensure it is the right strategic and financial fit for us.

Understood. And then I had one kind of bookkeeping question with regard to the act on recovery. So, those margin uptick, does that show up mainly in the gas G&P segment or should we expect that in the NGL segment? The reason I ask is, I noticed that with this guidance update you moved up the G&P segment guidance EBITDA whereas the NGL segment EBITDA guidance has moved down a little bit.

This is Sheridan. You will notice the increase from incentivized ethane reflected in the NGL segment. However, our forecast for the rest of the year does not include any incentivized ethane. Therefore, any additional ethane we manage to extract from the Bakken would be considered an upside.

Thank you very much. I have another question about the renewals. Considering the economics and the investments involved, does transitioning to electric or ultimately renewable sources provide a lower cost basis for you? Or is it more of a value-added service that you could charge existing customers extra for, particularly in relation to ESG factors? I'm trying to understand what the potential return on investment could be and whether you would secure contracts for renewable investments or possibly invest in some of these facilities.

It could be any of those options or potentially all of them. We have situations where if we can obtain power at a lower cost that is also cleaner and renewable, we would definitely pursue that. We are in a position to benefit from such opportunities. In other areas of our business, those power costs might be transferred to our customers, allowing us to assist them. We may also be able to supply power directly to our assets. We are keeping our options open on how we approach providing renewable energy for our assets.

I think it's important to note that we need to continuously update our compression technology as older machines become outdated or fail. This replacement process can sometimes lead to opportunities that contribute to our rate base. These updates can be part of our regulated assets where we earn a guaranteed return. The key difference is we may use electric compression instead of fossil fuel or other types of compression that we are currently considering. This could take various forms as well.

Makes sense. And then maybe just a follow-up. Just given the kind of the backdrop of the growth potential it probably isn't a big priority, but just with respect to M&A, is there any maybe desire to kind of diversify geography a little bit more kind of balance it Bakken relative to the Permian? Are there any assets that might be interesting? Or is it just tough to compare that relative to what's internal?

Well, I mean, we're always thinking about those types of things. I can tell you right now the appetite from a large-scale M&A standpoint is not very high, but we are always thinking about what opportunities are out there that we could bolt-on to the asset footprint that could make it better. So we're always thinking about those things. But certainly they've got to be strategic got to make a lot of sense. They've got to be accretive from an earnings and credit standpoint. All of those things are going to be required on the M&A front. But I will tell you candidly, the prospects are kind of few and far between, but we're always looking.

Great. Thanks so much.

Hey, everyone. I have a quick question. I didn’t notice this in the release, maybe I overlooked it. In your initial guidance, the rate for the G&P segment was projected to be between $0.95 and $1. It actually came in at $1.04 this quarter. Should we take this to mean that we should expect the rate to decrease for the remainder of the year?

Timm, this is Chuck. We previously provided guidance this year that the average fee would be between $0.95 and $1. It's been $1.04 for the last two quarters. I would suggest that you can estimate around $1, and we may see some quarters where it exceeds that. There could also be occasions where it falls just short by about $0.01. Overall, I believe $1 is a solid figure, and you may notice a few cents above that as the year progresses.

Okay. Got it. And the follow-up is, I'm going to assume if I ask you for fixed and variable cost on your system to get ethane down to the Gulf Coast, do you want to answer that? But what are the kind of main fixed costs and variable costs to think about as you think of that ethane coming down to the Bakken? And how does that vary from the Mid-Con to the Bakken, if at all in a big way?

Timm, this is Sheridan. Yes, you're correct. I won't specify what the cost is, but the variable cost primarily refers to the expenses associated with transporting it from the Bakken and processing it through a frac, which includes electricity and gas. The key difference between transporting from the Bakken versus the Mid-Continent is that the Mid-Continent is closer to Mont Belvieu, resulting in less pumping capacity and fewer pumps needed for the transport. Therefore, the variable cost difference is not significant.

Okay, I understand. That's all I have. Thank you.

Hey, guys. Thank you for taking my question. One or two easy ones. First of all, in the G&P segment in the quarter, I didn't see you all call out any volumetric impact due to Winter Storm Uri. Was there any? That's kind of the first question. The second question a lot of your peers or several of your peers that benefited in February from what happened with gas are now tied up or caught up in efforts to try and actually recover the cash from their customers some of which has sparked litigation already. Just curious, do you have the cash in the door for all of it? I didn't see a big accounts receivable balance buildup. So just wanted to see and maybe check on those two items?

Yes. Michael, this is Chuck. Regarding your second question, we have been paid for the gas sales made in February, so we have no accounts receivable related to that. As for your volume question concerning the impact of Winter Storm Uri, it primarily affected us in the Mid-Continent region. As Kevin mentioned, the impact was 30 million a day for the quarter, amounting to 2.7 Bcf. Essentially, during a 10-day event in the Mid-Con, it would be 270 million a day for those 10 days. Our plants and producers faced well freeze-offs, and there were some power issues at the plants. Therefore, the main impact was seen in the Mid-Continent for our gathering and processing, with only a minor effect in the Bakken, which is always challenging in February.

Got it. Given the ongoing discussions in the Texas legislature for the past couple of weeks, almost two months now, how do you see the idea of weatherizing your Permian infrastructure? This isn't just for you and Terry; it might be a discussion happening with your peers. How does the industry approach this?

I can speak for ONEOK. We have improved our weatherization efforts. The main challenges occurred in the field, particularly with wellhead production, which is tough to weatherize effectively. While the Bakken region was only slightly affected by severe conditions, Texas and parts of Oklahoma don't have as robust weatherization practices as we do in Williston. There's much to learn from producers who work in harsher environments regularly, particularly in terms of weatherization methods for Texas. A significant issue arises from the difficulties of weatherizing wellhead production, especially when power outages occur, impacting critical heating and insulation systems. At ONEOK, we did an excellent job weatherizing, enabling us to continue operations with very few facilities affected by freezing temperatures. We were able to maintain gas deliveries, even with rising market demand due to the cold. Thankfully, this cold spell only lasted about 10 days. Overall, ensuring everything is weatherized is a challenging task, but I can confidently say that ONEOK performed well.

Got it. Thank you, guys. Much appreciated.

Thank you.

Thanks so much. I was wondering if I could just ask quickly on Northern Border and the Btu spec limit discussion. Now, you have a bit of distance from the technical conference and response from FERC last year. So, I was just kind of wondering where the process stood at this point. Whether it's discussions with producers or any next steps with FERC? Thank you.

Yes. Robert, this is Chuck. TC Energy is the operator of Northern Border. And in discussions with them, we understand they're still working with the customers up in the Upper Midwest as well as the downstream pipelines that they interconnect with, looking to develop a tariff solution that addresses the operational concerns and balances the interest of parties from the Bakken on into Chicago. So more to come.