Q3 2022 ONEOK Inc Earnings Call
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Good day and welcome to the one oak third quarter 2022 earnings conference call and webcast.
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I would now like to turn the conference over to Andrew Viola Vice President of Investor Relations. Please go ahead.
Thank you Betsy and welcome to <unk> third quarter 2022 earnings call, we issued our earnings release and presentation. After the markets closed yesterday and those materials are on our website.
After our prepared remarks management will be available to take your questions.
Statements made during this call that might include one offs expectations or predictions should be considered forward looking statements and are covered by the safe Harbor provision of the securities acts of $19 33, a 1934.
Actual results could differ materially from those projected in forward looking statements.
For a discussion of factors that could cause actual results to differ please refer to our SEC filings.
Just a reminder for Q&A, we ask that you limit yourself to one question and one quick follow up in order to fit in as many of you as we can.
Good morning, everyone and thank you for joining us.
On our call this morning.
We appreciate your interest and investment in our company on the call today is Walt Hulse, Chief Financial Officer, and Executive Vice President Investor Relations and corporate development.
Kevin Burdick Executive Vice President and Chief Commercial Officer also available to answer your questions are Sheridan swords, our senior Vice President natural gas liquids and natural gas gathering and processing and Chuck Kelley, our senior Vice president of natural gas pipelines.
Yesterday, we announced strong third quarter 2022 earnings affirmed our 2022 financial guide guidance mid points and provided our 2023 growth outlook to exceed $4 billion of adjusted EBITDA.
Our third quarter results demonstrate the resiliency of our strategic and integrated assets and some of the most highly productive U S shale basins.
Our employees who are dedicated.
Have dedicated themselves to the safety and reliability and sustainability of our operations.
Looking forward, we expect continued strength in producer activity and increased volumes and higher earnings from our fee based services in all of our business segments, and a favorable commodity price and increasing demand backdrop, so with that I will turn the call over to Walt for our discussion.
<unk> of our financial performance and the expectations are and our insurance update so well.
Thank you Pearce.
One <unk> third quarter 2022, net income totaled $432 million or <unk> 96 per share a 10% increase compared with the third quarter 2021.
And a 4% increase.
Compared with the second quarter.
Third quarter, adjusted EBITDA was $902 million of.
A 4% year over year increase.
And an increase from the second quarter.
Higher results.
<unk> from increased Rocky Mountain region, NGL, and natural gas volumes and higher realized commodity prices net of hedges and higher average fee rates. Additionally, we had lower interest expense due to our lower debt balances and increased capitalized interest.
Third quarter 2022 results reflected our $5 million property insurance deductible related to the Medford incident, and approximately $30 million of losses related to the 45 day business interruption waiting period under the terms of our insurance policy.
We received notice in September that our Medford property insurers agreed to pay $100 million.
Unallocated first installment of insurance proceeds.
And as of today, we received $45 million of that amount.
And expect to receive the remaining amount before year end.
We've applied this cash received to our outstanding insurance receivables.
After the waiting period ended we incurred costs subsequent to the 45 day business interruption waiting period.
[noise] of $21.7 million.
Primarily related to third quarter, So I'm, sorry to third party fractionation agreements.
[noise] recorded a partial impairment charge of $6 $7 million, representing the value of associated with certain Medford facility property based on the limited assessments completed to date.
There is no income statement impact of these incurred business interruption costs or impaired impairment charges as they are fully offset by insurance receivables.
Yeah.
We continue sharing information with our insurance carriers to refine ongoing business interruption insurance coverage and to determine the ultimate path to replacement of this temporary loss of fractionation capacity.
We will provide additional updates as we move forward in this process when material information is available.
And lastly for the third quarter, we ended with higher NGL inventory levels that have since been sold forward that we will we will realize $17 million, earning benefit from those sales in the fourth quarter and first quarter of 2023.
As of September 30, our net debt to EBITDA on an annualized run rate basis was three eight times and we continue to view three five times or lower as our long term aspirational goal.
We currently have no long term debt maturities until September of 2023, and we have no material exposure to floating rate interest rates through our current outstanding long term debt.
Yesterday, we affirmed our 2022 guidance midpoint of $1 $69 billion for net income and $3 $62 billion for adjusted EBITDA.
We now expect total capital expenditures of $1 $2 billion, driven by our acceleration of spending on the MB five fractionator and smaller scale expansion projects that were not previously planned for 22 across our three business segments that will contribute to growth.
In 2023.
Key drivers for 2023 outlook, although more than 10% increase compared with our 2022 mid points to exceed $4 billion and adjusted EBITDA include continued strength in fee based earnings and rates.
Stable to growing producer activity, providing higher natural gas and natural gas liquids volumes in our system and expected higher realized commodity prices due to higher hedges. These.
These tailwind into 2023 from our base business additional insurance recoveries related to Medford, and our strong financial position provide us confidence in our double digit earnings growth outlook for next year I'll now turn the call over to Kevin for a commercial update.
Thank you all let's start with our natural gas liquids segment.
Rocky Mountain region, NGL volumes increased 17% year over year, and 12% compared with the second quarter 2022, driven by volume recovery. Following the April severe weather and overall volume growth, including higher Incentivised ethane on our system.
Volumes have remained strong in the region with September averaging more than 380000 barrels per day.
Third quarter mid continent, NGL volumes decreased year over year, and compared with the second quarter due primarily to lower ethane recovery on our system.
In the Permian Basin, NGL volumes were unchanged year over year and compared with the prior quarter with a recent third party plant connections in October we expect volumes from this region to increase through the remainder of this year and into 2023.
We also continue to see interest from customers seeking additional NGL takeaway out of the Permian. So we will continue to evaluate future low cost expansions on our system.
From a 2022 NGL volume guidance perspective, we expect to be near the midpoint of our guidance range due mostly to the ethane rejection, we have been seeing in the mid continent and the impact of the April storms.
Regarding ethane beginning in September we started to see lower demand for ethane from the pet chems, leading to more ethane rejection across most regions the.
The decrease in utilization has been driven by lower NGL demand globally, especially in China, and Europe , along with some pet Chem outages.
We expect ethane demand to remain muted somewhat in the fourth quarter and into early 2023, and this has been factored into our 2022 and 2023 expectations.
As we sit today, we are seeing ethane and ethylene inventories starting to get worked off which we believe will lead to increasing demand in 2023.
As for one oak. It is typical that we don't incentivize as much ethane out of the Bakken during the winter season, due to higher natural gas prices and natural gas demand, but we will continue to be opportunistic.
As it relates to our 2023 outlook, we expect the Permian to be in full ethane recovery, the mid continent to be and partial recovery in the Rockies continuing to provide opportunities to incentivize recovery.
Construction continues on our 125000 barrel per day MB five fractionator in Mont Belvieu, which we still expect to be completed early in the second quarter of 2023 and is reflected in our updated 2022 capital guidance.
Moving on to the natural gas gathering and processing segment.
Producer activity remains strong in the Rocky Mountain region with third quarter processed volumes, averaging $1 4 billion cubic feet per day, a record quarter for us.
Our average fee rate also increased reflecting the impact of contract escalators higher volumes on higher fee component contracts and a larger percentage of our total volumes from the Rockies.
On a go forward basis, we expect this average rate to range between $1 10, and $1 20.
Year to date, we've connected 244 wells in the region. We now expect to complete approximately 375, well connections near or at the low end of our guidance due to the impact of the April storms timing of some wells coming on and availability of completion crews.
And materials Act.
Activity still remains high just some timing elements that we now expect will push a few large pad completions into next year.
These same factors also let us adjusting our volume expectations for 2022 to be near or slightly below the guidance range.
There are currently more than 40 rigs in 18 completion crews operating in the basin with more than 20 rigs and approximately half the completion crews on our dedicated acreage.
As we've said before approximately 15 rigs on our acreage can maintain natural gas production at current levels, but with more than 20 currently on our acreage, we expect to see higher well connections and volumes in 2023 compared with 2022.
The 200 million cubic feet per day. It makes like three processing plant under construction remains on schedule to be completed in the first quarter and will bring needed capacity to the region.
The basin wide DUC inventory remained stable at around 500, considering the increasing rig count and activity with half of those on our dedicated acreage.
And the mid continent region, we continue to see increased activity with four rigs now operating on our acreage and more than 50 rigs basin wide we.
We expect steady to increasing activity and volumes through the remainder of the year and into next year with the majority of rigs basin wide driving additional NGL to our system.
In the natural gas pipeline segment with.
With strong year to date results benefiting from the continued increasing demand for natural gas storage and transportation services. We now expect this segment to exceed the high end of its guidance range of $400 million to $430 million.
We are highly subscribed for our storage services in Oklahoma, and Texas at higher rates and for longer terms, including our recent expansion of our Texas storage facilities, which is now fully subscribed through 2032.
Additionally, we are expanding our storage capabilities in Oklahoma, enabling an additional 4 billion cubic feet of storage capacity to be contracted.
This project is expected to be complete in April 2023, and is nearly 90% subscribed through 2029, and we are also evaluating an additional expansion of our Texas storage assets.
And lastly, before I turn the call back to peers, we began a compression electrification project on our Interstate Viking gas transmission pipeline to improve operational reliability and provide future greenhouse gas emissions reductions on the system the.
The project is expected to cost $95 million and be completed in the third quarter of 2023 and is included in our outlook.
That concludes my remarks, thank you Walton and Kevin.
As we enter the last couple of months of 2022.
And look forward to the next year I am proud of our employees and want to thank them for their hard work and contributions to continue to focus on operating safely sustainably and environmentally responsible.
And our key to our success as a midstream operator.
How we operate is important but also how we engage with our employees communities and other stakeholders is equally as important.
Also important for one oak is to remain focused on meeting the growing energy demand for today, even as it looks forward to helping drive the energy transformation needs for the future.
We also recently announced that one O joined with two other large publicly traded companies based in Oklahoma in a venture capital firm defined an effort to transform Oklahoma into a hub of energy technology startups and redefine a sector that has shaped the region's economy for more than a century.
We believe this partnership aligns to our long term business strategy, which includes potential low carbon investments that contribute to low long term growth and business diversification.
One of them has been building the right teams and resources to better participate in the innovative practices and technologies that is at six now and those that may play a role in the future.
Before I turn the call over for Q&A I wanted to highlight an important ESG item, we mentioned in our earnings release.
One hopes MSCI ESG rating was recently reviewed and updated by MSCI to triple from double a.
And we maintained our industry leader status.
As I previously said, our ESG efforts are a source of pride for one oak and we are committed to continuing to make progress in these important areas.
With that operator, we're now ready for questions.
We will now begin the question and answer session to ask a question you May Press Star then one on your Touchtone phone.
If you are using a speakerphone please pick up your handset before pressing the Keith.
If at any time. Your question has been addressed and you would like to withdraw your question. Please press Star then two.
At this time, we will pause momentarily to assemble our.
Our first question today comes from Brian <unk> with UBS. Please go ahead.
Yeah.
Hi, good morning, everyone.
Good morning, maybe to revisit some of the assumptions in your prepared remarks around 23 earnings growth. It seems like we should see some tailwind on volumes and hedges rolling higher but was curious if we could just dive a little bit further into ethane recovery assumptions for 'twenty. Three historically you guys have been pretty conservative on this assumption, but curious of how we should think about.
How btu concerns plateauing ethane demand for the next few years and Permian Nat gas tightness impacted some of your assumptions as it relates to Rockies recovery into 2023 and that 10% earnings growth.
Hey, Brian This is Kevin I'll start and then Sheridan can can add in.
Think about the overall 2023 growth outlook, we expect our volumes are going to be up both NGL and gathering and processing and all of our basins with the tail wins with the existing rigs we're seeing today.
As those carryover into 'twenty three so volume growth is going to be the primary driver.
You've also got Youre going to have a full year of <unk>.
The contract fee Escalations, So we'll see a full year of that you've got a step up in our hedging. If you look at the hedged prices we have in 'twenty three compared to 22, that's going to be a significant step up there.
The ethane recovery assumptions are pretty similar to what we had going into 'twenty.
Going into 'twenty two.
As we mentioned full recovery, we expect out of the Permian partial in the mid continent, and will continue to incentivize ethane out of the Bakken where where appropriate.
And with that I'll just add on that is when we look at 'twenty three as we look in 'twenty two.
We have limited incentivize the ethane coming out of the Bakken factored and we really see that as an opportunistic opportunity going forward.
Great I appreciate that color, maybe just to pivot towards capital allocation for a minute.
Oh, it is trending towards its leverage targets and payout payout ratio targets. Obviously there are some.
<unk> that were you know partially alleviated.
Earnings around the insurance proceeds but was curious of how we should think about the return of capital framework looking into 'twenty three.
Given that you had the same dividend level since 2019, but that said never cut at the same time, so any color there I appreciate it thanks.
So Brian this is this is pierce.
With our positive earnings growth indications for 2023.
Our payout ratio and our debt to EBITDA metrics are indicating that we are going to have more flexibility to execute on one or more of the capital allocation levers that are going to be available to us.
To create that value for our shareholders as we progress through 2023.
No.
That's the way I'd answer your question there.
Great Fair enough I'll leave it there have a great rest of your morning.
Thank you Brian .
The next question comes from Michael Blum with Wells Fargo. Please go ahead.
Thanks, Good morning, everyone.
Wanted to ask.
The latest on northern border.
Where does that stand in terms of gas coming from Canada versus the Bakken is there any more room, there and then related to that.
Any update on a potential expansion project on northern border.
Yeah, Michael It's Kevin for your first question.
We estimate there's still probably three to 400 million a day of gas coming from Canada that will continue to get displaced from Bakken as Bakken grows so <unk> got some opportunities there and also we're in active discussions with multiple parties.
On various residue takeaway and demand projects actually some demand projects in basin.
We have secured about 100 million a day of takeaway solution on WBI, that's going out south that doesn't go to northern border. So that's going to help them. So we don't think there's one single solution that provides that's going to provide that but we do believe there will be.
To find and there will be the nessus the necessary capacity out of the basin as we move forward.
Okay. Thanks for that.
I guess second question just wanted to ask I know you haven't really made a decision yet about whether youre going to.
Rebuild medford or maybe build something else at Mont belvieu or otherwise. So just curious if you could talk to the dynamics. If you do choose to not rebuild med for does that change anything in terms of the market dynamics between Conway and Mont Belvieu.
As it relates to Sterling.
Okay.
No I mean, there will be a little bit of an impact on that if we build down in Mont Belvieu view that bar down in there, but today or when Medford was up most of our liquids was transported down sterling and wait to the Mont Belvieu market. So we think overall the market dynamics are not going to be impacted that much whether we build it in medford or at Mont Belvieu.
Great. Thanks, so much.
The next question comes from Jean Ann Salisbury with Bernstein. Please go ahead.
Hi, good morning, and the third quarter, there was more ethane recovered from the Rockies and less from the mid con than I would have expected and is it fair to say that most of the time either to recover ethane from the mid con before the Rockies that maybe it was specifically due to echo price blow outs in the quarter that it was Philadelphia flips from Asia.
Yes, we are.
We look at the gas basis is really what kind of drives us on which base and we're going to incentivize. So yeah, heiko pricing versus what's going on in the mid continent will drive, what's going where we incentivize ethane coming out of there. We did see a lot of benefit in the third quarter coming out of the Rockies.
Due to the basis and what we can secure gas prices for and sell them for ethane. So that we see that as a great opportunistic two basins that we can antibody incentivize at times and kind of play that gas basis between the two so we think that's a big advantage to our system.
Okay. That's helpful.
And assuming that the Bakken does go back to higher injection in the next couple of quarters and I think the northern border Btu spec at that receipt point, it's probably going to exceed the 1100, which I think northern border asked how does kind of the Max.
Ask that they really want.
Thing happened, then or is that just kind of a whole FERC process.
But an actual cabin.
Yeah.
Jean Ann this is Kevin.
Yes, as you reject more ethane that will raise the btu content on northern border.
If you are we're back to about where we were pre COVID-19 and that number was north of 1100 right. Now there is not a spec on the pipe.
So.
The northern border, it's our understand they'll watch it they've.
They've got some levers to pull if it gets too high in downstream markets.
Start to have concerns.
They continue to work with shippers and all the relevant stakeholders to potentially go back to FERC for a spec but.
We don't have an exact timing on that so we'll watch it if it gets to the point, where it gets the btu level gets too high and downstream markets start.
You know raising issues then we always have the option to route to recover ethane to lower it back and if we do that if it's required at that point, then that would require I mean that would be at full rates not not in an incentivized rate.
Great.
That's all for me thank you.
Okay.
The next question comes from Jeremy Tonet with Jpmorgan. Please go ahead.
Hi, Good morning, This is Steve Mcgee on for Jeremy.
Just starting along the insurance line as far as a business interruption interruption insurance goes.
Just trying to get an idea of of what's covered under that does that include optimization marketing.
And there as well and then for the 2020 for 2023 does that include does that include the business insurance as well.
Yeah.
Well as we said on the last call.
Coverage that we have is that we are in.
Entitled to.
Receive coverage so that we get returned to what we would have made but for this event. So its system wide. So if that does impact.
Other parts of the business like optimization and marketing that gets factored into our <unk> calculation. The money that we received in September a road that we booked in September .
I wouldn't necessarily look at as a run rate.
Because there still are some moving parts that we're working with the.
Insurance companies too.
Refine how we look at going forward.
Those those costs were predominantly the third party frac costs and as we work with them and refined how much optimization and marketing we do expect to.
To receive some benefit from that going forward.
In 'twenty to 'twenty, three we expect our <unk> coverage to continue.
And at that point.
On a pretty regular amongst the months.
Catch up.
We're hoping that that you really don't see any any real variation from from the <unk> insurance going forward.
Understood. Thank you and then I guess flipping over to Capex you pulled some forward.
Ah well connects kind of towards the lower end of the guide, but still up a little bit this year, so I'm guessing.
Most of the uptick this year is the MB five should we expect.
I guess, a little bit less capex into 2023, now because of that and just if you could walk us through I guess at that.
That raised this year and then what that looks like into next year as well.
Yes, Steve this is Kevin.
Yes, <unk> five was a significant mover in in moving some of that capital forward into 'twenty. Two we also had a compressor station up north in the Bakken.
That we went to move forward with that will add to our growth in 'twenty three.
We referenced the Viking compression project in the in our opening remarks, and then we just had a handful of smaller routine growth type projects that typically have extremely strong multiple or strong earnings power from them and that will contribute in 'twenty three is.
Well, so just a combination of those factors are what led into the increase in 'twenty two.
Youre thinking about 'twenty three correctly, if once we complete MB five and <unk> three.
That would lead you probably to a little step down in capital barring other projects that we continue to work on that that could be approved that's the unknown at this point is.
We're constantly working on new projects that.
And as they reach F. I D. We will announce them, but absent. Those then yeah, you would expect our capex to maybe come down a little bit in 'twenty three.
Alright, great. Thank you I'll leave it there.
The next question comes from Theresa Chen with Barclays. Please go ahead.
Okay.
Hi, there. Thank you for taking my question first.
First I would love to touch on the 2023 guidance in Dallas into some of the assumptions here, mainly if you could provide some color on your price deck assumption and then in terms of Bakken activity in particular and any color you can share on assumptions for rig counts well completions and execute.
Growth in oil or gas and then granted.
Recovery dynamic remains.
In development can be volatile, but any sort of color you can give on deep recovery assumption in 2023 persons.
The level that you just reported for our third quarter 2022.
I'm curious if this is Kevin we're not again, we're not going to get into the detailed guidance specifics that will release, probably sometime next early next year.
But I would tell you as we think about price decks and activity levels.
Theres, probably more rig if you just look at today. There are there is more activity in the basins that we're looking at that we're talking about then we have in that outlook. So the activity levels. We're seeing today are plenty strong to help us achieve that.
Exceedance of $4 billion.
Got it.
And in the gathering and processing segment that dollar 16 average fee rate quite a step up from the previous run rate and understand.
The color you shared on the fee escalators and the composition of that.
Just trying to think about the trajectory of growth here was there anything in particular driving this and as we think about the escalators in 2023 and beyond should we assume a similar magnitude of step ups or generally speaking how should we think about this line.
Theresa this shared.
When you think about that margin, what's driving that increased step up a lot of it was on escalation is where it came from some on that contract mix being on we've got volume on higher contracts have more margin contracts and on others as we go forward.
A big thing Thats going to drive as we get into 'twenty three it keeps being the extra trajectory is what the inflationary escalators are going to be and we'll have to see how inflation comes out and how that.
We go against CPI had most of the time on that how CPI reacts for in 'twenty three eight versus 22 is going to be a big driver on where we land on that and going forward. So it's really going to be based on inflation.
<unk> piece.
Thank you.
The next question comes from Michael Cristiano with Pickering Energy Partners. Please go ahead.
Hi, good morning, everyone.
Wanted to first focus on the natural gas liquids optimization and marketing number that Youll noted a $44 million decrease sequentially.
Was any of that a result of Medford at all or.
Was it just other I think Youll mentioned, some price price differentials and timing on the Ngls.
Michael This is Sheridan yeah, Medford did have an impact on those numbers and that's factored in there in that 45 day waiting period, we did take some hits in optimization and marketing is there and as you mentioned the other things we have is.
Spreads were a little bit narrow during that time, we have for sales due to Medford.
That we push for sales forward that we will receive some of that money or $17 million that money in the first quarter and seven second quarter.
Sorry, fourth quarter and first quarter as we go forward. He will look at that 17 million back. So that those are the three main factors as you see in that.
Drop in optimization and marketing.
Okay, and just to clarify you would expect to be in the future you would expect it would be.
Alright, alright.
We expect to recoup.
Insurance proceeds.
In the event of any optimization and marketing reductions.
What happened, we do and we do expect to get insurance proceeds, but a lot of that $45 million as we part of that is in the 45 day waiting period, which we wouldn't get that.
That's on us, but going forward.
We expect to get any losses, and marketing and optimization that we would have received if metro. It had been up we expect insurance to cover that.
Okay that is helpful.
And then.
Previously you all have given like a.
Our current <unk> run rate out of the Bakken for.
NGL takeaway.
I think you gave a September number any indication you can have for what October looks like going forward.
Michael we're not going to provide kind of the numbers in Q4. We gave you the number for September that was a that's a really good run rate.
If you think about it.
As we move through we get into the fourth quarter and you start bringing whether into play so.
So that's why we backed off that.
Yeah.
Okay understood.
And then last one if I can.
If I break up the insurance proceeds from one allocation from business interruption and the other for property loss.
Are you all viewing the property loss as.
Replacement cost or is it.
Getting back the frac capacity to where Mackenzie MB five recover some of that I'm, just trying to think of like how that shapes out for <unk> and the insurance company.
Thinking about it.
No we have specific coverage that would cover the replacement or the repair.
Of the facility.
To get it back to the point, where we would achieve the 210000 barrels of capacity that we currently have so we have property coverage to put us back in the same position that we were before.
And then but we do have the flexibility with those dollars that it would cost to do that.
Build it wherever we want to do that and that's what we're still.
Considering at this point.
Forward, we would expect to.
Likely not get as much not get on allocated money.
This was.
It should be allocated out for.
For the B I on a monthly basis once we get into kind of a monthly rhythm and the property will be what it is as we spend the money for the the repair.
There are replacement of the facility.
Okay.
That's helpful.
Would envy five since it was already undergoing construction.
So hoping that you could allocate any sort of property last Q or would it be in no.
No Andy.
And beyond if you wanted to MB five has its own Standalone project.
We built because we needed it and.
We are obviously it'll help us a little bit.
It comes on and we were going to be in a natural ramp up phase but.
That is part of our capital in the.
Proceeds that we received for the repair or replacement of the Medford facility will be discrete and it will cover those costs.
Okay. That's all really helpful. I appreciate it that's all for me. Thank you.
Okay.
This concludes our question and answer session I would like to turn the conference back over to Andrew <unk> for any closing remarks.
Alright. Thank you all our quiet period for the fourth quarter starts when we close our books in January and extends until we release earnings in late February we'll provide details for that conference call. At a later date have a good day and thank you for joining us.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
Okay.
Yes.
Yes.