Q1 2021 ONEOK Inc Earnings Call
Good day and welcome to the first quarter 2021, one of our earnings call. Today's conference is being recorded at this time I would like to turn the conference over to Andrew <unk>. Please go ahead Sir.
Alright, Thank you Travis and welcome to <unk> 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 will be available to take your questions.
A reminder, that statements made during this call that might include one offs expectations or predictions should be considered forward looking statements and are covered by the safe Harbor provision of the Securities Act 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 and one of them.
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 Kelly Senior Vice President natural gas.
One O solid first quarter results are providing positive momentum as we enter warmer operating months BOL.
<unk> 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.
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.
Tabled us to operate with very few interruptions.
Operations teams ensured our assets, where weatherized for extreme conditions.
And that our employees were onsite 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 work to help one O provide essential natural gas and Ngls when needed most.
Spite these extraordinary winter weather conditions, we continue to meet the critical needs of our customers, including natural gas utilities and electric power plants.
Our natural gas pipeline and storage assets, we're particularly well positioned to address the need 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.
And our base business was evident in our Rocky Mountain region, NGL and natural gas volumes during the quarter.
Williston Basin continues to outperform expectations and provide us with solid and stable earnings.
As I've said before one oak's earnings growth in 2020, one 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 one oak and our strategic assets in key operating areas.
With yesterday's earnings announcement, we raised expectations for 2021 and now expect adjusted EBITDA growth.
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 towards 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 of 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 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.
And the many end use products they helped 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.
And now expect net income midpoint of 1.35 billion or $3 <unk> 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 pipelines 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 Yuri.
Total capital expenditures for 2021, including growth and maintenance capital remain unchanged from our original expectations of $525 million to $675 million.
And more than 70 per cent decrease compared with 2020.
This range includes capital to complete the Bear Creek plant expansion and associated field instruction 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.
One of his first quarter 2021, net income totaled $386 million or <unk> 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.
It makes us from dividends paid during the quarter.
Our March 31, net debt to EBITDA on an annualized run rate basis was $3 nine eight times compared with four six 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 93, and a half cents or $3 74 per share on an annualized basis unchanged from the previous quarter.
Healthy earnings in the first quarter provided momentum from 2021 and helped to accelerate our deleveraging efforts it's Terry.
He mentioned increasing producer activity ample capacity on our systems and the continued opportunity for flare gas capture and strong gas oil ratios in the Williston basin and increasing F. N ethane demand continue to support our base business and increased 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 Yuri 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 Yuri.
System wide volumes were reduced by an average of approximately 64000 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 11000 barrel per day impact from winter storm Yuri.
As we sit today volumes from the region have reached more than 300000 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 incentive some ethane recovery, which we've 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 net backs 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, Yuri 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 100000 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.
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 we will be and indications from several of our producers in the basin point to increasing activity.
In the second half of 'twenty, 'twenty, one, particularly in Dunn County.
In response to this we've resumed construction on our bear Creek processing plant expansion and.
And expect it to be complete in the fourth quarter of this year.
Once complete we will have approximately one seven 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 tailwind 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.
<unk> a continued opportunity for us to bring this volume on to our system and help further reduce flaring in the basin.
The gathering and processing segment's average fee rate remained $1.04 per M. M. Btu during the quarter unchanged from the fourth quarter 2020.
Winter storm, Yuri 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 95 cents to one dollar per M and Btu 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.
With volumes trending upward and strength in our base business. Our outlook continues to improve but we remain disciplined in our approach and focused 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 serve.
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've 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 <unk>.
<unk>.
Thank you if you would like to ask a question. Please signal by pressing star one on your telephone keypad. If you were using a speaker phone. Please make sure. Your mute function is turned off to allow your signal to reach our equipment you can press star one to ask a question.
Yes.
Our first question comes from Michael Blum from.
Fargo.
Thanks, Good morning, everyone.
Where my couple of questions for me one day.
The TNF right out of the Bakken I mean, it's not a big deal, but it did fall by a penny versus last quarter to 27 cents from 28, just wanted to know if that was something to do with your ethane recovery incentive incentivize centralization program or is there something else that we should be thinking about.
Michael This is shared and you are right that ticked down in the average rate was due to the amount of ethane that we incentivize 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.
Many rigs are running on your acreage today in the market.
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.
J P Morgan.
Hey, Good morning, guys. This is James on for Jeremy maybe.
Maybe just want to start here on the on the Bakken outlook, you mentioned the 350 docs on the acreage.
And the unchanged G N P. A 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 for the remainder of the year, you mentioned <unk> and <unk>, 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.
The remaining quarters here for to meet the well completion got.
This is Kevin are James the yes, absolutely like we said in the remarks, we expect a significant increase in the completions.
No Chuck and his team. These conversations we're having with producers are literally days and just a couple of weeks old and and we anticipate a pretty sizable step up in Q2.
In 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 it would need we will see a pickup in the in the summer and James This is Chuck what I would add to what Kevin said is we completed the 30 day in Q1, but a lot of that planning was done back in.
Q4, and a lot of the producers still had some uncertainty over you know stability of crude pricing what was the apple going to do so, but 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 he or she is obviously topical with emissions. These days and maybe just looking across your Nat gas pipelines footprint.
You now 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 in the initial stages there.
Yes, James this is Terry.
Certainly we have remained very focus over the years and in particular in the last couple of years, reducing our emissions impact across across our asset footprint not just in natural gas and liquids as well.
So that's 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 as things like electrification of compression natural gas fired compression being converted to.
Two electrics, which then can consume or be in a position to consume renewable power.
That's a key focus we have had 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.
To continue to steadily increase our fleet of electric compression.
So.
That's you know that's.
That is that's a key focus I know obviously the renewables team is working on a lot of other things are on the on the energy transition front taken advantage of the of our skill set and taken advantage of the of the pipeline processing capability or expertise that we have.
So.
So that's kind of it in a in a nutshell, Kevin anything you can add to that.
And I guess as far as capital, Yes, we have a 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.
Allocated some meaningful capital there, it's not a huge amount of capital as we're just getting started in this but as we as we move as we move forward, we expect that capital to pick up I think the key the key emphasis is that projects that we 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 no that makes sense I appreciate that just last one for me if I can sneak one in.
You guys have a number you can share or color you can share on where you see a 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'd 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 that's going to taper off.
Yeah, that's increased over 15% just here in the past year.
You can see that in our chart.
Got it thanks for the questions I'll leave it there.
Thanks James.
If you find that your question has been answered you may remove yourself from the queue by pressing star two.
Our next question comes from share.
<unk>.
Yes.
Hi.
Good morning, everyone and thanks for.
We're taking our questions today just.
Terry 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 you're sort of intimating that 'twenty two can grow by high single digits or low double digit I guess kind of back of the envelope that it sounds like about $3 4 billion.
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 you know kind of understand the cadence with respect to 'twenty, one, but how have the conversations changed with producers with oil now in the sixties for for some time like how they evolved since February is that.
What were 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 mentioned momentum uses that word because he used that word I'm going to let him [laughter]. Thanks Terry.
No.
It's it's all the things that you mentioned conversations with customers not just our G&P customers, but as Sheridan and his team worked with their customers.
Across all the basins.
It's just that we we anticipate increasing activity we've seen prices stabilize here appear.
At a nice level clearly that can generate a fantastic returns in most every basin we're in.
The gas to oil ratio increasing in the Bakken gives us more confidence that youre going to continue to see those.
Williams 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 theyre going to work the DUC inventory I know a lot's been written about well, where the rigs well theyre going to work their DUC inventory.
Down first and then as that declines and it gets back to more than normalized rate then, we'll probably see and we expect to see rigs come back based on our conversations with them.
So so all of those reasons are why we think in the back half of the year you will see an increase in.
And it tick up I'm, not you know not necessarily and completion crews, but in rigs and.
And that will provide the momentum as we go into 'twenty two.
Kevin the only the only thing I'd add to kevins remarks, as Jim just when you think about the worldwide recovery.
From the pandemic certainly that's that's providing a lot of momentum to us and where we see it not just in commodity prices that are that are relatively strong, but also we're seeing it in pet chem demand.
We had we got hammered.
The pet Cam space got hammered here in the Gulf Coast, obviously due to weather, but we've seen that that.
Net pick back up in those operations restore we also see new petrochemical plants being built across the 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 it's certainly it's a big part of our story as we think about 2022 and in <unk> and beyond.
No I really appreciate the.
Really appreciate the color there and I was wondering if we can also expand on the conversation or the.
From the prepared remarks about ethane recovery in the in the Rocky Mountains. You you sort of described how you were purchasing at a premium and selling it at Mont Belvieu and I think you've stated that you know 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've kind of outlined as the upside potential but are you is it kind of like a day to day decision or where this is occurring where.
Where are you signing some more smaller term contracts in the 369 or 12 month nature I'm just trying to understand.
You know, whether it's day to day or or could there be some momentum on some smaller term type contract deals.
Shneur. This is Sheridan yeah, we are doing this day to day to be able to capture the most spread between the market. So.
We saw that in February where the price of gas Spike really high and 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 100000, 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 it 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 they begin to capture the spread for what we buy it on the gas price and what we sell are for ethane. If we can 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.
Kyle.
Alright, perfect. Thank you very much guys really appreciate the color today.
Thank you.
Yes.
Our next question comes from Christine Cho Barclays.
Thank you.
I actually wanted to also touch upon the 'twenty to 'twenty two comments.
Is there any more color you can provide on the different basins like what your you know what you're thinking about cross in.
In the Bakken versus mid Con freshness Permian.
I'm just kind of in context of how you guys say that you are not you know I'm anticipating.
Increased activity in the mid con.
In 2021 results, but curious how that in the Permian looks for 2020 accounts, especially in the 50 to $70 price environment.
Okay.
Christine This is Kevin I mean, we're not going to provide a lot more color at this point because it's you know it's an outlook, but clearly when you look at our footprint, we feel pretty strong about the Bakken, we think theres going to be growth. There. We've got a great position in the Permian, we've seen activity levels pick up there.
As well and but no I don't think it's gonna from our mid continent perspective, as you know we don't have a lot of growth baked into that to that in that basin.
Okay.
And then I wanted to also touch upon Bear Creek I know in your prepared remarks, you talk about Dunn County, seeing you know a lot of activity and I know there've been some big welfare and I know that you will have a plant there but is that full already or are the producers currently flaring. The gas there are building a DUC inventory.
I just wasn't sure if you were able to move sales volumes to be processed at your other plants from Mckinsey.
Terry.
No Christine this is Kevin we you know we've talked about that plant 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 other plants, but 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 and in Continental and marathon and Conocophillips and X T O 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 should we expect like kind of a stair step and and volumes when that plant comes on or is it still going to be more right.
Slow ramp.
I think the way a lot of the developments occurring nowadays, it's it'll be a little lumpy I mean as they bring on pads.
But but yeah.
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 <unk> of credit Suisse.
Hey morning, guys too.
Two questions for you on Capex first one just thinking about bear Creek tubing official now I think that was already contemplated in the original Capex range. So I'm. Just curious is that sort of push you towards the higher end of the range and if not why not.
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.
Things that would get you to the higher end is 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, two and routine growth, which are things like well connects in 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's just going to be timing as far as.
How the how the capital spend over the course of the year.
Got it that's helpful sticking with Capex sounds like a lot of the growth you guys are contemplating in 2022.
Don't require capex it sounds like very much continuation of a lot of the trends you're seeing in in 'twenty. One. 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 'twenty, one if not maybe even below these levels.
Yeah.
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 in our remarks about the capacity, we'll have in the Bakken from a processing perspective, we recently completed our expansion on Elk Creek to bring it up to 300000 barrels a day and we've still got the legacy Bakken NGL line combined with O P. P. L that we could always use.
We talked about the minor expansion on our buckle too weak.
We've got capacity in West, Texas, So we can grow our EBITDA without a significant.
Uptick in capital so yeah, you're probably going to think of it more in lines of a of a 2021 without talking about 'twenty two more in line of that versus we're not gonna have to.
Add another long haul pipeline or something like that.
And then Kevin Kevin That's got point kits.
Kits Spiro Spiro, let's hang on with me for a second I mean that segue to an important an important point to make that with this excess capacity that we have available and the fact that all of this infrastructure is pretty well in place for the next the next three or four years without any sort of major backbone type transmission.
<unk> 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 expand a heck of a lot of capital. So I mean, I think that that that.
Expand on that that headroom concept or that available capacity concept that we keep trying to.
Rest of 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 if they're in the right pricing environment right activity levels. I mean, we could see a $4 billion kind of EBITDA number here.
Okay.
Okay I appreciate those comments Derek thanks, Kevin.
Sure.
Our next question comes from Tristan Richardson Truth Securities.
Hey, good morning, guys really appreciate all the commentary on completion activity and what you're seeing or thinking about for 2022.
Yeah on 2022.
As you start to see well connects accelerate throughout the year should we think of 'twenty. Two is a kind of a well above that 300.
Well connect type of marketing you're talking about for 'twenty, one and you noted potential for rig additions.
Our rig addition, something we could see as early as the second half or is this more of a based on conversations that youre, having misses that exiting the year type of event.
Tristan this is Chuck I'd say that the the rig the rig activity we anticipate.
Certainly.
Would start to you'll start to see rig showing up here toward the end of spring and the beginning of summer it's definitely a second half.
Activity as Kevin referenced earlier, and our producers have told us that they're willing to work through their DUC inventory first and then bring the rigs. Unlike the traditionally do midyear.
And ramp that up you know what we've got you know 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 in the wells.
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 to next year.
<unk> certainly seen no less than that obviously, so without really getting into 2022 specifics.
Specifics.
We think we're gonna have a lot of tailwind behind us this year and going into next year.
That's helpful. And then just a clarification question Kevin.
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 do we've provided the information previously that every 25000 barrels a day of volume coming out of the Rockies is worth about $100 million of EBITDA.
That's just doing the math there of the 100000 barrels a day of ethane if it all came online at full rates would be worth $400 million of EBITDA per year.
Well that's 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 that cash.
The first one is about on slide 10, it looks like February flaring tip that ticked up a day from the declining trend that we had seen in prior months and was that a one day to whether or some other reason or does it suggest that we're heading a gas constraints somewhere and that could create that mark.
Yeah. Julian this is Chuck that that was pretty much due to weather and then a little bit of Oh drilling.
Drilling in some areas it a little hard to get through right now but it.
It is not it's not an indication of increased flaring forthcoming in the basin.
Okay.
And then I guess my question sorry, Terry.
And my second question, what I'll say about Dan and scented ethane from the first quarter.
Was that was that that they were sort of some temporary gas blowouts in the basin or something more structural like gas basis is gradually widening there and it's hard to tell because northern border kind of take some from the Bakken income from Canada, but is this sort of the fact that now it Dan.
The money for you today than before it wasn't to get something structurally changing in terms of gas takeaway getting limited.
Yeah. 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 and 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 wanted to take advantage of it and we continue to see that grow, especially now as we head into May we're seeing a lot of increased demand for ethane.
The Gulf Coast from our assets down there probably as strong as we've seen in the last three or four years, but we need to make.
Perfect and that's all for me thanks.
Okay.
Our next question comes from Craig Shere Tuohy brothers.
Good morning, congratulations on the good quarter.
Thanks, Greg trying to understand better.
The roughly 10% year over year of 22, EBITDA uplift outlook.
If I understand correctly the 'twenty one updated guidance includes up to $50 million of headwind on adopt will shut down.
What if anything are you incorporating into 2022.
When you say.
You know, maybe roughly 10% uplift for the Apple and then if I understand correctly the answer to <unk> question, while you're assuming.
A recovery in rig counts to filling the docs there is no assumption and to your 'twenty two outlook for it.
And increasing Frac crew deployment is that correct.
Craig I think there's a couple there's a couple things in there one you you referenced dapple.
If you think about we've talked previously about the impact we believe to dapple at this point in talking to our customers is is quite small.
Given the time, that's now passed we're well into the year and the pipelines still operating and Theres still you know not a clear path of what's going to happen to it.
The EIF is supposed to be complete by the I think March of 'twenty, two so even in the scenario, where it would get shut down I don't know that there's that much impact to 'twenty two.
As everybody believes that process is going to will ultimately get the permit.
So from that standpoint, that's how we're thinking about dapple.
And on the rig counts, we kind of answered that previously that we absolutely believe there'll 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 'twenty two.
Remains to be seen and that's why.
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 Youre 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 <unk>.
Frac crews.
Rig counts to fill in the docks yet but.
But if we get another two or three frac crews that that could add to what you're talking about is that correct.
Yes.
Right 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 didnt, we didnt get it here.
Just you know Youre your Permian realized NGL pricing is lower because there's still a lot of legacy.
Just just transport only and trying.
Trying to get a sense for the outlook of being able to.
Switched to more and more integrated services that will give a higher bundled rate.
Well what I. This is Sharon 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.
Putting pressure on that sort of 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 at a lower rate. So I don't see a whole lot of up tick in the average rate on the West Texas system.
But the ability to combine the transport on West, Texas with our fractionation to get higher all in.
No 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.
Oh 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 the clean energy investments I think you would have heard that.
Jim.
I'm going to hold those projects to see them kind of economic accounts.
No most of the recent a publix you're dead.
On the NGL pipelines up to trial or more like four to five X EBITDA multiples. So I was just curious you know when you think about this being investment risk versus reward how should we be thinking about any incremental investments in that day, especially if you look at Ccs and all those kind of channel.
<unk> technologies.
This is Kevin I mean, as Terry mentioned earlier was we evaluate these projects we were 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.
Probably not but is it going to earn a reasonable return.
Yes, we believe they will so.
So we will definitely is if we're if we're spending capital we're going to be looking for a return on that capital.
Understood.
Any clarity on timeline on those decisions on those evaluations.
Where we are our team is working it hard I mean, theres a lot of opportunities out there and we are evaluating them.
To look and see how they fit with our footprint with our capabilities in and are in the need for us to get involved in 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 heard anyone kind of book keeping question.
With regard to the act and recovery.
So those those.
Margin uptake does not show up in.
The gas G&P segment.
Should we expect that in the NGL segment. The reason I ask because you know.
I noticed that.
Guidance update you moved up the G&P segment guidance EBITDA.
This is shared and you will see the uptick from incentivize 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 incentivize 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.
Yeah.
Thanks very much.
Maybe just another question on the renewables.
It does it and thinking about the economics, and how you want to make the investment to cause like a conversion to electric or even ultimately renewables mean like like a lower cost basis for you or is that something that maybe kind of a value add that you can kind of upcharge.
And customers really for lack of a better term kind of ESG related matters.
Trying to think of what the investment at the return could be and ultimately as well from a renewable investment standpoint is that something what you had.
Really contract or is it maybe even maybe even investment in some of these facilities.
It may be any of those or all 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 would absolutely do that and we.
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.
Help out our customers.
We may be in a situation, where we can provide the power.
Two the asset so we're not constraining ourselves one way or the other and how we're thinking about.
Providing renewable power to four assets.
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.
Machines become antiquated or.
But as they as they wear out we need to replace that compression anyway. So sometimes some of that those opportunities can be <unk>.
<unk> to the rate base or that.
They can be in our regulated assets, where they can we can earn a guaranteed return.
The only differences will put an electric compression as opposed to fossil fuel compression or by field 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 that kind of the backdrop of the growth potential it probably isn't a big priority.
With respect to M&A is there any desire to kind of diversify geography, a little bit more kind of balance it.
And 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, we're always thinking about those those types of things I can tell you right now the appetite from a from a large scale M&A standpoint is not very high but we are always thinking about what's.
What opportunities are out there that we could bolt on to the 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 gotta make a lot of sense I gotta be accretive from from earnings.
And a credit standpoint.
All of those things are going to be required.
On the M&A front, but I will tell you candidly.
The 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 Tim Snider City.
Hey, guys just a quick one on I didn't see this in the release, maybe I missed it but.
On your initial guidance I think the rate for in the G&P segment was 95 cents to a Buck I came in at a dollar for this quarter. So as I said directionally imply we should be assuming that rate to go down throughout the rest of the year.
Tim This is Chuck I would you know we gave guidance earlier this year on the average feed being 95 to $1. It's been a dollar for the past two quarters I would just say you know you could probably hang your head on a dollar and we're going to have quarters, where we're above it and.
Might be just a penny or so below it but I think our I think $1. A good number you might see you might see a couple of cents above that throughout the year.
Okay got it and my 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, you won't 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 midcon to the Bakken if at all.
All in a big way.
And this shared and I would say, yes, you're right I'm not going to answer what it is but.
The variable cost is just the pulp cost deposits from the Bakken Andrew run it through a frac this electricity and gas to do that that's the only difference the difference between can't bring it out of the Bakken versus the mid continent is just that the mid continent is closer to the Mont belvieu than the Bakken as 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 makes sense.
And that is a that's it for me. Thank you.
Okay.
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 I'll call out any volumetric impact due to winter storm Yuri.
Was there any that that's kind of the first question the second question.
A lot of your peers are several of your peers that benefited in February from what happened with gas.
Alright are now tied up per caught up in efforts to try and actually recover the cash from their their customers. Some of which has sparked a 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 sanity check on those two items.
Yeah. Michael This is Chuck I have a second question first no we've been paid for 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 here. It was primarily a net mid continent, Inc.
In fact for US as Kevin mentioned in his remarks. It was 30 30 million a day for the quarter. So 30 by $92 seven Bcf. So you know essentially if you had a 10 day event and the mid Con 270 million a day per 10 days so.
Our plants are playing our producers behind those plants, obviously have Wolfe resource plants had some power issues. So was primarily a mid continent.
The mid continent issue for us in GMP had a little bit of an impact in the Bakken, but February is always tough from 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 two almost two months now a little over two months now.
How do you think about the concept of Weatherizing your Permian infrastructure and not just you and Terry this might be a conversation you're having with your peers how does the industry do that.
Hello.
Alright, I can speak for one oak, we've weatherized. Okay. I think we're a bulk of the problem was is back in the field, where it's very difficult it's difficult to Weatherized wellhead production.
It's been done in the Bakken obviously, the Bakken had you know had marginal impact from the.
Severe conditions, but.
Down in Texas, and even in parts of Oklahoma.
Not quite we don't do it as robustly as we do so.
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 tap to how the weather is but I mean, a lot of issues.
Dan from the fact that.
It's difficult.
In terms of wellhead production to weather is.
And especially as the electric Power's getting shut off on your two if you're a producer and you're trying to you're you know you've got heat tracing and installation requires electric power and then your powers getting shut off it makes.
I mean, you're.
You froze up so.
I can speak for one of 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 due to due to freezing and we had.
Large volumes of gas coming out of storage that made up for the for the wellhead supply that froze off we just continued to make deliveries and those deliveries in the day market demand was going up dramatically. So even in the face of rising demand because of the cold temperatures.
The rock N roll and maintained deliveries. Unfortunately, this cold snap only lasted about 10 days, but.
But anyway, that's it's a challenging it's a challenging undertaking to make sure everything's weatherized.
I can I can speak for one of them, we did a great job.
Got it. Thank you guys much appreciate it.
Thank you.
Okay.
Sure.
Our last question comes from Robert CAD Morgan Stanley.
Thanks, So much I was wondering if I could just ask quickly on northern border and the Btu spec when that discussion now you haven't been a distance from the technical conference and the response from FERC last year. So I was just kind of wondering where the process stood at this point, whether its discussions with producers or any next steps with FERC. Thank you.
Yeah, Robert this is Chuck.
TC energy as the operator of northern border and in discussions with them. We understand there is still working with the.
The customers up in the upper Midwest as well as the downstream pipelines that 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.
More to come.
Great. Thank you.
Yeah.
At this time I would like to turn the call back over to Andrew <unk>.
Alright, 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.
Okay.