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ONEOK Inc
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Good day and welcome to the First Quarter 2021 ONEOK Earnings Call. Today's conference is being recorded.
At this time, I would like to turn the conference over to Andrew Ziola. Please go ahead sir.
All right. Thank you, Travis and welcome to ONEOK's first 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.
A reminder that 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. Our first speaker this morning is Terry Spencer, President and Chief Executive Officer. Terry?
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 continues 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 remain 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 to 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 10% and adjusted EBITDA guidance 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 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 quarter -- 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 cost 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 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 incented some ethane recovery, which we have talked about in the past.
On a short-term basis, we were able to incent 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 an 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 quarter, 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.
Thank you. [Operator Instructions] Our first question comes from Michael Blum, Wells Fargo.
Thanks. Good morning, everyone.
Good morning, Michael.
A couple of questions for me. One, the T&F rate out of the Bakken I mean it's not a big deal, but it did fall by $0.01 versus last quarter to $0.27 from $0.28. Just wanted to know if that was -- that has anything to do with the ethane recovery incentivized -- incentivization program? Or is there something else there that we should be thinking about?
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.
Our next question comes from Jeremy Tonet, JPMorgan.
Hey, good morning guys. This is James [ph] 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. The -- yes absolutely. Like we said in the remarks, we expect a significant increase in the completions. Chuck and his team these conversations we're having with producers are literally days and just a couple of weeks old. And we anticipate a pretty sizable step-up in Q2 and Q3. Q4 is always a little dependent on the weather as you think about that, but we still feel really good about our 300 guidance. So yes it would need -- we'll 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 what was DAPL going to do. So we didn't anticipate Q1 will 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 color there. And then ESG is, obviously, topical with emissions these days. And maybe just looking across your nat gas pipeline footprint, have you guys looked at opportunities there to reduce carbon emissions? And what maybe is that project set? And if you have -- have you guys allocated a set dollar amount there yet? Or are you still kind of in the initial stages there?
Yes, James, this is Terry. So certainly, we have remained very focused over the years and in particular in the last couple of years 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 return 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 the thing to do is I just go back over the time. We provide the information of the trend that's happened over the last -- what is it 70-plus percent over the last four years or something like that. And we have no reason to believe that's going to taper off.
Yes, it's increased over 15% just here in the past year. You can see that in our chart.
Got it. Thanks for questions. I will leave it there.
Thanks, James.
[Operator Instructions] Our next question comes from Shneur Gershuni, UBS.
Hi. Good morning, everyone. Thanks for taking our questions today. Just -- Terry I just kind of wanted to focus on some of your prepared remarks that you made around momentum building towards the end of the year. And that ex-storm you're, sort of, intimating that 2022 can grow by high single-digits or low double-digit. I guess, kind of, back of the envelope that sounds like about $3.4 billion.
I was wondering if you can talk about the momentum a little bit. And in the answers to your previous questions you have talked about the completions towards the end of the year and so forth. So kind of understand the cadence with respect to 2021. But how have the conversations changed with producers with oil now in the 60s for some time? Like how they evolve since February? Is that where some of the momentum is coming from? Or is it strictly related to gas/oil recoveries 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 all the things that you mentioned. Conversations with customers not just our G&P customers, but as Sheridan and his team work with their customers across all the basins. It's just that we anticipate increasing activity. We've seen prices stabilize here appear at a nice level. Clearly, that can generate fantastic returns in most every basin we're in.
The gas to oil ratio increasing in the Bakken gives us more confidence that you're going to continue to see those volumes tick up. So there's just a lot of factors that go into that. And I think a key -- as we have conversations with the producers particularly in the Bakken, the note is as they're going to work the DUC inventory, I know a lot's been written about well where are the rigs? Well, they're going to work their DUC inventory down first, and then as that declines and it gets back to more of a normalized rate then we'll probably see and we expect to see rigs come back based on our conversations with them. So all those reasons are why we think in the back half of the year, you will see an increase and a tick up not necessarily in completion crews but in rigs. And that will provide the momentum as we go into 2022.
The only thing, I'd add to Kevin's remarks is just when you just think about the worldwide recovery from the pandemic certainly that's providing a lot of momentum to us. And we see it not just in the commodity prices that are relatively strong, but also we're seeing it in pet chem demand. And we've got hammered -- the pet chem space got hammered here in the Gulf Coast, obviously, due to weather. But we've seen that pick back up and those operation's restore. We're also seeing new petrochemical plants being built across the global space. So, pet chem demand showing no signs of letting up and certainly that's why ethane is a big part of our story. And certainly, it's a big part of our story as we think about 2022 and beyond.
I really appreciate the color there. I was wondering, if we can also expand on the conversation from the prepared remarks about ethane recovery in the Rocky Mountains. You sort of described how you were purchasing in a premium selling in Mont Belvieu. And I think you stated that the potential from this is not currently in your guidance today. I was just wondering, if you can walk us through this? Obviously, you're providing incentives so it would be less than the 400 million that you kind of outlined as the upside potential, but are you -- is it kind of like a day-to-day decision where this is occurring? Or are you signing some more smaller term contracts in the three, six, nine, or 12-month nature? I'm just trying to understand, whether it's day-to-day or could there be some momentum on some smaller term type 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 out 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?
Really right now as we see it we think we are better served by doing it day-to-day instead of -- because we get to capture the full -- we get to capture the spread for what we buy it on the gas price and what we sell it for ethane. If we lock in a longer term, we'd have to lock in that spread and we think that that spread is going to continue to widen. So we'd rather do it on a day-to-day basis at this time.
All right. Perfect. Thank you very much guys. Really appreciate the color today.
Thank you.
Our next question comes from Christine Cho, Barclays.
Thank you. I actually wanted to also touch upon the 2022 comments. Is there any more color you can provide on the different basins? Like, what your -- what you're thinking about growth in the Bakken versus Mid-Con versus Permian? Just kind of in context of how you guys say that you're not anticipating an increased activity in the Mid-Con in 2021 results, but curious how that and the Permian looks for 2022 especially in a $50 to $70 price environment?
Christine, this is Kevin. I mean, we're not going to provide a lot more color at this point because it's an outlook. But clearly, when you look at our footprint, we feel pretty strong about the Bakken. We think there's going to be growth there. We've got a good -- great position in the Permian. We've seen activity levels pick up there as well. And -- but no I don't think, it's going to -- from a Mid-Continent perspective, it's -- we don't have a lot of growth baked in to that 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 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.
Got it. Thank you.
Our next question comes from Spiro Dounis, Crédit Suisse.
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 Kevin that's a good point. Spiro, let's hang on with me for a second. I mean that segues into an important point to make that with this excess capacity that we have available the fact that all of this infrastructure is pretty well in place for the next three or four years without any sort of major backbone type transmission project needing to be built in the NGL space.
I mean you could see this business from an EBITDA perspective hit a $4 billion type of number in the right pricing environment without having to expend a heck of a lot of capital. So -- I mean I think that expands on that headroom concept or that available capacity concept that we keep trying to express to the market to understand about our business that we built a lot of that major infrastructure is already in place and the rest of this stuff is smaller routine growth. So -- and that's what puts us in a position.
In the right pricing environment, right activity levels, I mean we could see a $4 billion kind of EBITDA number here.
Okay, appreciate those comments Terry. Thanks Kevin.
Sure.
Our next question comes from Tristan Richardson, Trust Securities.
Hey, good morning guys. I really appreciate all the commentary on completion activity and what you're seeing -- thinking about for 2022. Just on 2022, as you see -- start to see well connects accelerate throughout the year, should we think of 1022 as a kind of well above that 300 well connects type of mark that you're talking about for 2021?
And you noted potential for rig additions. Are rig additions something we could see as early as the second half? Or is this more of a -- based on conversations that you're having this is an exiting the year type of event?
Tristan this is Chuck. I'd say that the rig activity we anticipate certainly would start to -- you would start to see rigs showing up here toward the end of spring and the beginning of summer. It's definitely a second half activity. As Kevin referenced earlier, our producers have told us that they're going to work through their DUC inventory first then bring the rigs in like they traditionally do midyear and ramp that up.
And with -- we've got one good indicator up there right now. We've gone from two to eight completion crews in the basin. And you think about completion crews and the well connects that we have for the balance of the year; we're pretty excited about hitting that 300-plus number.
And as we look into next year, certainly see no less than that obviously. So, without really getting into 2022 specifics, we think we're going to have a lot of tailwinds behind us this year and going into next year.
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?
No, that's just -- we provided the information previously that ever 25,000 barrels a day of volume coming out of the Rockies is worth about $100 million of EBITDA. So, that's just doing the math there of 100,000 barrels a day of ethane if it all came online at full rates would be worth $400 million of EBITDA a year.
Okay, great. Super helpful. Thank you guys very much. Appreciate it.
You bet.
Our next question comes from Jean Ann Salisbury, Bernstein.
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 was pretty much due to weather and then a little bit of drilling in some areas that are a little hard to get to right now, but it is not -- it's not an indication of increased flaring forthcoming 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.
Our next question comes from Craig Shere, Tuohy Brothers.
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?
Craig, I think there's a couple of things in there. One you referenced DAPL. If you think about we've talked previously about the impact we believe to DAPL at this point and talking to our customers is quite small. Given the time that's now passed, we're well into the year, and the pipeline is still operating, and there's still not a clear path of what's going to happen to it. The EIS is supposed to be complete by the, I think, March of 2022. So even in the scenario where it would get shut down, I don't know that there's that much impact to 2022 as everybody believes that process is going to -- will ultimately get the permit.
So from that standpoint that's how we're thinking about DAPL. Just -- and on the rig counts, we kind of answered that previously that we absolutely believe there will be an uptick in rigs and activity levels in the second half of this year, as to what that exactly looks like as we move into 2022 that remains to be seen and that's why the range is provided.
And Craig, we wouldn't have said it if we didn't have visibility to it. You know us too well.
Absolutely. I guess, I'm trying to get at if you're kind of saying that you expect at least maybe 300 well connects next year that doesn't sound like it's -- that comments assuming any healthy uptick in frac crews. Rig counts to fill in the DUCs, yes. But if we get another two or three frac crews that could add to what you're talking about. 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.
Well, what I -- this is Sheridan. What I would say is that I don't see a whole lot of uplift in that average rate. One is we are seeing a lot of pressure on rates for new volume out in the Permian that's out there right now that's putting pressure on that. So our legacy volumes are going to be where they're at, because they're on long-term contracts. But I think as we bring new volumes on they will be at a lower rate. So I don't see a whole lot of uptick 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.
Our next question comes from Sunil Sibal, Seaport Global Securities.
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 kind of technologies?
This is Kevin. I mean, as Terry mentioned earlier, as we evaluate these projects, we are going to maintain our financial discipline, our economic thinking and the return standards that we have. Does that mean it's a four times project like some of our others, probably not. But is it going to earn a reasonable return? Yes, we believe they will. So, we will definitely -- if we're spending capital, we're going to be looking for a return on that capital.
Understood. Any clarity on time line on those decisions on those evaluations?
We are -- our team is working it hard. I mean, there is a lot of opportunities out there and we are evaluating them to look and see how they fit with our footprint, with our capabilities and the need for us to get involved and the opportunities. So, we're not going to rush it. It's important to us. We're working hard at it, but it's not something we're going to do just to say we've got a project. We're going to again make sure, it's the right strategic and financial fit for us.
Understood. And then I had one kind of book-keeping 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 see the uptick from incentivized ethane showing up in the NGL segment. But in our forecast for the remainder of the year, we do not -- we did not forecast any incentivized ethane in that forecast. So that will all be upside if we find the opportunity to bring more ethane out of the Bakken.
Okay, got it. Thank you.
Our next question comes from Alex Kania, Wolfe Research.
Thanks very much. Maybe just another question on the renewals. Does it -- and thinking about the economics and how you want to make the investment, does like a conversion to electric or even ultimately renewables mean like a lower cost basis for you? Or is that something that maybe kind of a value-add that you can kind of upcharge existing customers really for lack of a better term kind of ESG-related matters? Just trying to think of what the investment of the return could be, and ultimately as well from a renewable investment standpoint is that something where you would really contract? Or is it maybe even investment in some of these facilities?
It may be any of those or all of the above. I mean we have situations where we may -- if we can secure power for a lower cost and it's a cleaner renewable energy, we'd absolutely do that. And we -- and have the opportunity to benefit in that. In other parts of our business that gets -- those power costs may get passed along. So we would help out our customers. We may be in a situation where we can provide the power to the assets. So we're not constraining ourselves one way or the other and how we're thinking about providing renewable power to -- for our assets.
I think the other thing, I can add to that Kevin is that on an ongoing basis, we're needing to replace compression in our footprint as we have -- as machines become antiquated or as they wear out, we need to replace that compression anyway. So sometimes some of that -- those opportunities can be additions to the rate base. So that -- they can be in our regulated assets where they can -- we can earn a guaranteed return. The only difference is we'll put in electric compression as opposed to fossil fuel compression or by field compression or some of the things that we're considering. So it could take that form 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.
You bet.
Our next question comes from Timm Schneider, Citi.
Hey, guys. Just a quick one. I didn't see this in the release, maybe I missed it. But in your initial guidance, I think the rate for -- in the G&P segment was $0.95 to $1. Came in at $1.04 this quarter. So does that directionally imply we should be assuming that rate to go down throughout the rest of the year?
Timm, this is Chuck. I would -- we gave guidance earlier this year on the average fee being $0.95 to $1. It's been $1.04 the past two quarters. I'd just say you could probably hang your hat on $1 and we're going to have quarters where we're above it. And there might be just $0.01 or so below it. But I think $1 is a good number. You might see a couple of cents above that throughout the year.
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. I would say yes you're right. I'm not going to answer what it is. But the variable cost is just the top cost to pump it from the Bakken and to run it through a frac. Just electricity and gas to do that. That's the only difference. The difference between bringing it out of the Bakken versus the Mid-Continent is just that the Mid-Continent is closer to Mont Belvieu than the Bakken is so you have less pumping capacity -- less pumps you have to run to get it down there. So not that big a variable cost.
Okay. Got it. No. that make sense. And that is -- that's it for me. Thank you.
Our next question comes from Michael Lapides, Goldman Sachs.
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. Second question first. No we've been paid for the gas sales that we made in February. So there are no accounts receivable out there for that. Secondly, your volume question on impact of Winter Storm Uri, it was primarily a Mid-Continent impact for us. As Kevin mentioned in his remarks, it was 30 million a day for the quarter, so 30 x 90, 2.7 Bcf. So essentially, if you had a 10-day event in the Mid-Con, 270 million a day for 10 days, so our plants -- our producers behind those plants obviously have well freeze-offs. Plants had some power issues. So, it was primarily a Mid-Continent issue for us in G&P. Had a little bit of an impact in the Bakken, but February is always tough in the Bakken.
Got it. And with all the debate going on in the Texas legislature over the last couple of weeks or so really last -- almost two months now -- little over two months now, how do you think about the concept of weatherizing your Permian infrastructure? And not just you and Terry, this may be a conversation you're having with your peers. How does the industry do that?
Well, I mean -- right. I can speak for ONEOK. We've weatherized, okay? I think where a bulk of the problem was is back in the field, where it's very difficult. It's difficult to weatherize wellhead production. It's been done in the Bakken. Obviously, the Bakken had marginal impact from the severe conditions. But down in Texas and even in parts of Oklahoma, we don't quite -- we don't do it as robustly as we do in Williston. So I think there's a lot to be learned from producers, who operate in a hostile environment all the time. A lot can be shared with producers down in Texas and how to weatherize.
But -- I mean a lot of issues stem from the fact that it's difficult in terms of wellhead production to weatherize. And especially, if the electric power is getting shut off on you too if you're a producer and you're trying to -- you've got heat tracing and insulation that requires electric power and then, your power is getting shut off it makes -- you're froze up.
So, I can speak for ONEOK. We did a great job weatherizing and that's how we were able to continue to operate. We had very few facilities go down due to freezing and we had large volumes of gas coming out of storage that made up for the wellhead supply that froze off. We just continued to make deliveries. And those deliveries and the market demand was going up dramatically. So even in the face of rising demand because of the cold temperatures, we are able to rock and roll and maintain deliveries. And fortunately, this cold snap only lasted about 10 days. But anyway, that's -- it's a challenging undertaking to make sure everything is weatherized. I can speak for ONEOK. We did a great job.
Got it. Thank you, guys. Much appreciated.
Thank you.
Our last question comes from Robert Kad, Morgan Stanley.
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.
Great. Thank you.
At this time, I'd like to turn the call back over to Andrew Ziola.
All right. Well thank you everyone for joining us. Our quiet period for the second quarter starts when we close our books in July and extends until we release earnings in early August. We'll provide details for the conference call at a later date and the Investor Relations team will be available throughout the day. Thank you for joining us and have a great week.
Thank you. Ladies and gentlemen, this concludes today's teleconference. You may now disconnect.