Q4 2022 ONEOK Inc Earnings Call
Hello, and welcome to the one Oak fourth quarter 2022 earnings Conference call. All participants will be in listen only mode should you need assistance. Please signal a conference specialist by pressing the star can you followed by zero. After today's presentation, there will be an opportunity to ask questions to ask a question.
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Please note. This event is being recorded I would now like to turn the conference over to Mr. Andrew <unk>. Please go ahead.
Thank you Amy and welcome everyone to <unk> fourth quarter and year end 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 <unk> expectations or predictions.
It should be considered forward looking statements and are covered by the safe Harbor provision of the securities acts of 1933 of 1934 <unk>.
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 with that I'll turn the call over to Pierce Norton, President and Chief Executive Officer Pearce, Thanks, Andrew and good morning, everyone and thank you for joining US. This morning on today's call is Walt Hulse.
Our Chief Financial Officer, and Executive Vice President Investor Relations, and corporate development, and Kevin Burdick, Executive Vice President and Chief Commercial Officer.
Also available to answer your questions are Sheridan swords, senior Vice President natural gas liquids and natural gas gathering and processing.
And Chuck Kelly Senior Vice President natural gas pipelines.
Yesterday, we announced strong fourth quarter and full year 'twenty two performance.
We met our 2020 to financial guidance expectations, despite weather related events and a significant operational incident. We also achieved our ninth consecutive year of adjusted EBITDA growth in 2022.
Through the efforts of our workforce and the resiliency of our assets. We have provided exceptional value for our stakeholders and are positioned to continue delivering growth in 2023.
I believe the term resiliency is a great description or the descriptor of 2022, and we will continue to be a focus of our operations going forward, our people assets and earnings continued to prove their resiliency flexibility and stability.
With yesterday's earnings announcement, we also provided 2023 financial and volume guidance expectations higher natural gas processing and NGL volumes and a strong fee based earnings are expected to contribute to higher earnings in 2023, as we continue to focus on both growing our core business.
And innovating for future opportunities there.
There are key differentiators of <unk> business that have proven critical to our past success and offer us confidence in the future. These differentiators provide stability resiliency and unique opportunities for growth.
First our solid and growing base business.
Which features strategically positioned assets in some of the most productive U S shale basins connected with some of the largest and most well capitalized producers in the U S, who provide stable and growing supplier to our systems.
Our margins in our core businesses are approximately 90% fee based with minimum direct commodity price exposure because of our proactive hedging strategy.
Second our strong balance sheet and investment grade credit ratings, which provides significant financial flexibility.
We've reduced our leverage to below to three five times and significant a significant milestone for us we provided investors with more than 25 years, our dividend stability and growth.
Not cutting our dividend during the Covid challenge years, and recently announced a dividend increase.
Third our proven track record of intentional and disciplined growth, we continued to benefit from significant operating leverage across our systems, enabling us to continue focusing on lower capital high return projects and investments to support producer growth across our operations.
Our strong return on invested capital as a source of pride for one up and is a key metric for evaluating our management's team performance annually.
Nearly 15% of our OFC in 2022 highlights the scrutiny that we place on investments the efficiency of our capital and the high quality of our projects earnings.
And this disciplined growth also approaches and we will continue finally, they continued demand of the energy products and services that we provide.
Which are vital to our national security and the quality of life, and which we believe will play an important role in transforming energy future.
Natural gas and natural gas liquids remain abundant and reliable the products that we move will continue to provide much needed energy domestically and globally. We enter 2023 from a position of strength driven by year of solid financial and operational performance and as you can see there are many.
The reasons why we are confident and optimistic about one oak's future with that I'll turn the call over to Walt for a discussion of our financial performance.
Thank you Pearce.
As we detailed in Yesterdays press release, we expect continued growth in our businesses in 2023 after achieving our 2022 financial guidance, even with some challenging events.
One <unk> fourth quarter and full year 2022, net income totaled $485 million and $1.72 billion respectively.
Representing increases of 28% for the fourth quarter and 15% for the full year compared with the same period in 2021.
Adjusted EBITDA also increased year over year totaling $967 million in the fourth quarter, 2022, and $3.62 billion for the full year or.
Our strong financial performance was driven by increased producer.
Activity higher realized commodity prices higher average fee rates.
And higher natural gas storage and transportation services.
In January we increased our quarterly dividend to <unk> 95, and a half cents per share or $3 82 per share on an annualized basis, marking a return to dividend growth following three years of dividend stability.
In November 2022, we completed a $750 million senior notes offering due in 2032 generating net proceeds of $742 million, which was primarily used to repay short term debt.
And just yesterday, we redeemed $425 million of 5% senior notes due September 23 with cash on hand.
Our year end net debt to EBITDA on an annualized run rate basis was 3.46 times in line with our previously discussed aspirational target of three five times or less.
As it relates to Medford, we reached an agreement with our insurers in early January to settle all claims related to the incident for total insurance payments of $930 million, which included $100 million that was paid in 2022.
We received the remaining $830 million in the first quarter of 2023.
And applied approximately $50 million to an outstanding 2022 insurance receivable.
We provided a table in our earnings release, showing the line by line details.
The remaining $780 million will be recorded as a gain in our operating income in the first quarter of 2023.
As Pierce mentioned with yesterday's earnings announcement, we provided 2023 financial guidance, including a net income midpoint of $2.41 billion and an EPS midpoint of $5 36 per share diluted share.
We also provided an adjusted EBITDA midpoint of $4.575 billion.
Our guidance includes the net effect of the onetime insurance settlement gain of $780 million and future Medford related costs, primarily third party fractionation, which we estimate will total $240 million in 2023.
We expect Medford related costs to be significantly lower in 2024 due to our ability to fully utilize the MB five fractionator to substantially reduce third party fractionation costs compared with 2023.
By taking the full settlement of $780 million less the $240 million of expected third party costs. In 2023, you get a total approximately $540 million related to the settlement that has been assumed in our four.
Five southern 5 billion adjusted EBITDA guidance midpoint for 2023.
Excluding the effect of the settlement in the third party costs of $540 million, there's still amounts to more than $4 billion double digit earnings growth, which we referenced on our last earnings call.
We also expect double digit earnings growth at the mid points for both natural gas liquids and natural gas gathering and processing segments, driven by higher volume expectations across our operations.
Kevin will provide more detail on each of the operating segments in a moment.
Our 2023 guidance assumes producer activity associated with W. T I.
Crude oil prices in the range of what we are currently seen in the market.
We expect total capital expenditures of $1.38 billion, which includes growth in maintenance capital.
This midpoint reflects the investments necessary to keep up with expected increase in producer activity. The completion of M. B five early in the second quarter of 2023, and also more than $300 million related to M. D. Six this year.
Excluding the M. B six expenditures, our total capex would have been lower than 2022.
Our 2023 Capex guidance does not include the swirl connector pipeline or any other projects that have not reached a final investment decision.
Our routine growth capital accounts for higher number of well connects and our higher return projects such as natural gas storage expansions pump stations and compression expansions to meet customer needs.
Finally, as it relates to the 15% alternative minimum tax associated with the inflation reduction Act, we expect the a M. T. Do you have an impact on our cash taxes, beginning with the 2020 for tax here.
You can find details in our 10-K when it is filed later today.
Thank you well we.
We saw strong full year natural gas gathering and NGL volumes on our system in 2022, despite several weather events during the year, providing continued growth in our primarily fee based earnings.
NGL volumes were particularly strong in the Rocky Mountain region, increasing 12% year over year due to higher activity levels and increased opportunities to recover ethane from the region.
Well connects across our operations increased 24% compared with 2021, and we saw a solid return of activity in the mid continent.
Driving a significant increase in well connections in the region and higher natural gas processing volumes on our system.
We'll continue to see the benefits of this activity throughout 2023 as volumes ramp.
Customers continue to see the value in our storage assets and we continue to evaluate opportunities to expand these services.
Turning to 2023.
Key drivers for our higher 2023 guidance includes stable producer activity, providing higher natural gas and NGL volumes across our systems continued strength in fee based earnings and rates and higher expected realized commodity prices due to hedges.
Placed at higher price levels compared with 2022.
At the midpoint, our 2023 volume guidance would result in a 7% increase in total NGL volumes and an 11% increase in total natural gas processing volumes compared with 2022.
And the natural gas liquids segment, we expect volume growth to be driven by strong producer levels of producer activity across our operations.
Continuing the momentum we saw from producers in 2022.
Higher average fee rates will also contribute to the segment's earnings as contract escalators continued to be realized throughout the year.
We expect this current market to drive increased activity from the U S petrochemical industry relative to global pet chems, while the U S position being with the U S position being one of the lowest on the global cost curve.
On our system, we expect the Permian basin to stay in high ethane recovery in 2023.
And for the mid continent to be in partial recovery as natural gas prices fluctuate seasonally.
We are on track to complete our 125000 barrel per day MB five fractionator in Mont Belvieu early in the second quarter of 2023, and we recently announced MB six which we expect to be complete in the first quarter of 2025.
We expect volume growth again this year in both the Rocky Mountains, and mid continent regions, driven by producer activity levels, resulting in more well connections than in 2022.
In the Rocky Mountain region, we expect processed volumes to grow 11% at the midpoint compared with 2022 and averaged nearly $1 5 billion cubic feet per day in 2023.
Already this year despite winter weather, we've reached our process volumes as high as 1.46 billion cubic feet per day in February a new record for the segment.
We completed construction on the 200 million cubic feet per day <unk> Lake three processing plant this month, providing our customers with needed capacity as well as operational redundancy.
Activity levels in the Williston Basin remains strong, particularly considering we are just entering March.
There are currently more than 40 rigs in 'twenty two completion crews operating in the basin compared.
Compared with just over 30 rigs and 13 completion crews at this time last year.
Producers remain committed to the region and we anticipate a few more rigs will return as we move into spring.
At our guidance midpoint, we expect to connect 500 wells in the region this year and nearly 40% increase compared with 2022.
We've already connected nearly 90 wells through February and have remained steady at more than 20 rigs operating on our dedicated acreage.
Additionally, there remains a large inventory of around 500 Ducks basin wide with approximately half on our acreage.
Keep in mind that in the Bakken producer economics are driven by crude oil and customers or our customers or some of the largest and most well capitalized in the country.
This means recent fluctuations in commodity prices and specifically lower natural gas prices have not had an impact on producer activity levels on our acreage.
We also expect gas to oil ratios to remain strong and continued to trend higher in the future, which can drive volume on our systems, even without increased producer activity.
In the mid continent region, we continue to see positive activity with approximately 10 rigs currently operating on our acreage and more than 50 across the region.
We expect processed volumes to grow 12% at our guidance midpoint, compared with 2022 and averaged more than 700 million cubic feet per day in 2023.
Rig activity across the basin, we'll also continue to drive additional NGL to our system.
And the natural gas pipeline segment, we continue to expect strong demand for natural gas storage and transportation services in 2023.
At the end of 2020 to nearly 80% of our natural gas storage capacity was contracted under long term agreements and our pipeline transportation capacity was nearly 95% contracted we.
We expect similar levels in 2023.
Work continues on a project that will expand our storage capabilities in Oklahoma by 4 billion cubic feet and we are currently.
Currently evaluating reactivating previously idled storage facilities in Oklahoma and Texas.
Construction also continues on our Viking pipeline compression electrification project.
The Oklahoma storage expansion and Viking project are both slated for completion this year.
Additionally, in late December 2022, but one oak subsidiary filed a presidential permit application with the FERC to construct and operate new international border crossing facilities at the U S and Mexico border.
The proposed border facilities would connect upstream with a potential one oak intrastate natural gas pipeline called the sorrow connector pipeline and with our new pipeline under development in Mexico for ultimate delivery to an export facility on the West coast of Mexico.
Since the announcement there have been several positive developments related to the potential LNG export project and a final investment decision on the one O pipeline is expected in mid 2023.
Pierce that concludes my remarks.
Thank you Kevin and thank you Walt.
We covered a lot today and we have many reasons to feel confident in our 2023 guidance and our expectations for more growth this year.
Everything that we've talked about today from our 2022 performance to our future expectations and key Differentiators for growth are all underscored by our commitment and focus on safety and environmental performance are.
Our company and our industry arent immune to incidents, but I'm proud of how we've responded when challenges do occur and how we continue working to improve our performance going forward focusing on safety and the health of our employees and the computing communities near where we operate.
From our environmental perspective, we've made significant progress toward our greenhouse gas emissions reduction target achieving reductions that equate to approximately 20% of our total 2030 reduction target our employees dedication to meeting customers needs, while operating our assets in safe reliable and environmentally responsible.
Manor continues to drive our strong operational growth and financial performance year after year, and we're set up well for continued growth in 2023.
With that operator, we're now ready for questions.
Well now begin the question and answer session to ask a question you May Press Star then one on your telephone keypad.
If youre using a speakerphone please pick up your handset before pressing the keys.
Jonathan the question queue. Please press star. Thank you.
At this time, we will pause momentarily to assemble our roster.
Today's first question is from Brian <unk> with UBS. Please go ahead.
Hi, good morning, everyone maybe.
Maybe to start off on the guidance you know last year, we had a couple of weather events and a material amount of frac capacity come offline, but no guidance is still achieved.
While some activity seems to have gotten pushed to 'twenty three from 'twenty to 'twenty guide seems.
Similar to 2022 original base guidance so.
Could you just talk about the puts and takes this year from last year and whether this is a base guide out performance are you know if we saw some volumes for JMP in Ngls can moved into 'twenty three.
I'm, Brian Yeah. This is Kevin I think the probably the big thing is just like you mentioned the volume that was offline and really the delays we saw when the volume came offline primarily in April when we had the severe just kind of historic weather events in North Dakota.
That just delayed not only getting volume back online, which hurt our 'twenty, two but but it delayed some of the well connects as we into pushed back into 'twenty three.
So that's why we feel really good about our 'twenty three guide.
Yes, we've got a significant step up in well connects but when you look at the 90 wells, we've already connected to date, which historically as some of our lower months from a well connect perspective.
And you look at the momentum we kind of built as we exited 22, we feel really good about where were at volumetric Liam both GNP and NGL out of the Bakken.
Great Thanks, and as a follow up just on <unk>.
Hum on capital allocation. It seems like we should have pretty stable capex for the next few years, what the N b six build out and just given the already announced dividend raise and leverage targets and payout ratios matter. At this point you know how should we think about use of excess cash going forward. Thanks.
But Brian that.
This is a good good question to kind of clear up and really focus on what our key strategies are for capital allocation.
The first one is that we want to invest in high return organic projects that are adjacent.
To our existing footprint.
The second thing is is that we want to maintain and grow a what we referred to as a sustainable dividend and what we mean by that is we want to keep that dividend growth somewhere below our EPS growth percentage and then also focus on our payout ratio, which I would say that.
Approximately 85% are lower so you know we were above 100%, we've got it down below 100% in our 2023 guidance and number three.
We want to keep our strong investment grade credit ratings with a target of that three five times debt to EBITDA.
And assuming that we've achieved all of those.
Kind of kept the allocation key strategies you know if we if we do have.
Excess cash or whatever we.
We could consider.
Consider share buybacks, but that's a that's kind of laying it out.
What are our priorities are from a capital allocation standpoint.
Great. Thanks appreciate the color I'll leave it I'll leave it there the rest of your day.
Thanks.
The next question is from Spiro <unk> with Citi. Please go ahead.
Thanks, operator, good morning, guys.
First question wanted to touch on the third party Frac fees.
You guys highlighted Mont Belvieu, five frac VI coming online and really sort of benefiting 2024 from the third party Frac fleet perspective, but.
I guess, just given the fact that does come on or it sounds like you to come on early in second quarter is there any ability to leverage that frac as well in 2023.
To the extent you've considered any of that in the 'twenty three guidance.
Spiro. This is Sheridan show when we had the Medford incident, we went out right away and secured frac capacity that we thought we needed going into 'twenty three and we already took into account that <unk> was going to come up in April so our what we contracted for Frac.
Pastis, obviously heavier in the first part of the year until MB five comes on and then drops off and that was all accounted for in the settlement that we had with the insurance company so well.
We have that already baked in and that's why there's not that much movement on the third party frac that we have obviously <unk> will help us if volume exceeds our expectation, we will be able to use <unk> for that.
<unk> and 'twenty.
Three.
Got it thanks, Thanks Teri Seck.
Question Multipart, one on the <unk> pipeline.
To the extent that does reach FID in.
Mid 'twenty three I guess, one would you expect any impact on the 'twenty three capex budget or is that kind of more of a 2024 plus item and then if you could just maybe give us any sense of.
The pipeline would be willing to take on JV partners and then finally just on the two eight Bcf a day of ultimate design capacity.
Obviously, it's a pretty big pipe should we imagine that that maybe comes on in phases or just how to think about the cadence there.
Spiro. This is Kevin are there still a lot of your questions. We're that's what we're working through right now we're not going to provide a capital guide them there'd be a little money that would be spent if we if I need this year.
But obviously the bulk with it coming on where the anticipation had come on in.
2025 time frame the most of the capital is going to get pushed is going to be pushed out.
Got it fair enough I appreciate the color guys. Thanks again.
The next question comes from Michael Blum with Wells Fargo. Please go ahead.
Hi, Thanks, good morning, everyone.
So I wanted to ask about ethane recoveries gave some broad expectations for ethane recovery across your footprint, but.
Gas prices are pretty weak it seems like they're going to stay there for a while can you just talk about opportunities for ethane recovery specifically in the Bakken in and what is actually reflected in guidance.
Yeah. Michael This is Sheridan, we have a very modest amount of ethane incentivised ethane in our guidance a little bit that we have already.
Tracked it and already locked down the spread we have not done any more than that as you said, we do see a lot of opportunity in 'twenty three with this low gas price, which Kevin mentioned in his remarks is making United States pet Cam very advantaged on using ethane as a feedstock going forward and we think that we will continue to see more.
Ethane recovery as we go through the year, especially as more demand comes on internationally.
We will pull the mid continent up to be more in ethane recovery later in this year and will allow us to incentivize more ethane out of the Bakken.
Wider spreads than what we have done today.
Okay, Great and then.
Also just wanted to ask another question about the Frac market.
It seems like everyone's, adding frac capacity and so I'm wondering if you think that's gonna be pressuring rates overtime at Mont Belvieu and within that context, how should we think about you know crack six how much of that is going to be.
Contracted with third parties versus a help for your own account.
Well, Michael what I'd say about frac capacity coming online.
In the NGL world that people that are building those fracs as us we contract that volume and build our fracs to be able to grow into so as these fracs come on you would probably see the spot market be a little bit weaker than it was when our frac went down but that long term those fracture contracted and then and as volume.
Comes on they will fill that in terms of N. B six member MB six is really just replacing Medford and so it can be six is completely contracted as Medford was completely contracted so when you're all the only looking at our our.
Add to our Frac fleet is the MB five that we had substantially contracted before the met Britt is set so I think youll see a little bit of softening in rates in the spot market, but long term I do not think you will see softening of rates.
Great. Thank you.
The next question comes from Harry Mateer with Barclays. Please go ahead.
Thanks, Good morning.
On the three and a half times leverage target you know Walt you've spoken about it as being aspirational for some time, but at this point before you closed out of 22 and given your 23 guidance. It seems it seems more and more reality than aspirational. So how are you thinking about it now is the plan to hold this level going forward or are you not ready to commit to that was <unk>. <unk> ahead of you and what is still a pretty.
Good oil price environment.
Well, Harry I think that we have definitely achieved the goal as we sit here today, given the fact that we had $830 million of infusion.
From the insurance settlement.
Over the course of the next couple of years, we obviously will utilize some of that cash to build out M. B six and we would expect to come back back into that.
Mm three five or below in the not too distant future.
We like that as a spot to give us flexibility going forward, but I think the appears walked through our our capital allocation thoughts earlier, you know, we're not concerned if it trails down a little bit lower as we look for projects, but I would just go back to pierce's discussion about our capital.
Location.
Yeah.
Okay. Thanks, and then my follow up just I know you guys recently redeemed one of your maturities later this year you have another one.
You know any any guidance you can give us on potential financing plans for the year and how you plan to manage potential debt capital markets needs.
Sure well, yes, youre right that we actually did the make whole because we could do it at par on the floor and a quarters are.
For me.
On the other coupon that we have later in the year as a seven 5%. So the make whole doesn't work so well wait until the actual contractual call date, which I think the first time, we can do that is early may.
You know I think you can assume that given the fact that we have had this cash infusion that we will take that out for cash at that point in time.
And we'll just assess our needs as we go through the year. If if there is a need for any further.
Issuance, but as we sit today, we will cover off our our.
Maturities with cash on hand.
Great. Thanks very much.
The next question is from Jackie <unk> with Goldman Sachs. Please go ahead.
Hi, good morning. Thank you so much for the time.
First I'd like just to focus.
Little bit on the macro front what are your thoughts in comfort level on Bakken gas egress out of the basin and further are you seeing the need for bison live or any other ways to add gas capacity there.
Yeah.
Jackie This is Kevin I'm, just kind of macro.
Bakken related from a gas takeaway perspective, we've talked before that.
We do believe there's still three or 400 million cubic feet a day of capacity on northern border that that the basin will continue to price out. So in other words displaced gas currently flowing down from Canada.
There has been 100 million a day roughly.
Project, that's kind of moves south and south west over to Arne WBI and gets down into the Cheyenne market that we've signed up for there's the northern border open season on Bison Express that we are actively involved in that are that T. C. L.
<unk> has said, they're working that project and have been pleased with the results. So far so theres an opportunity so from an egress perspective, we feel good obviously for the next you know that'll get you eat several years out even with some some solid growth.
And then obviously, we've got on our NGL system, we've got the ability to expand if we need to expand it by just adding pump stations, which is not a lot of capital and does not take a lot of time relative to some of the other projects, where we're talking about so based on overall feel very good about the macro environment.
We do not need to see more rigs show up in the basin to achieve our guidance are the rigs that are there today. When you also look at the you know finishing up some ducks they've got we're in really good shape to meet the volume guidance and.
Both the GNP.
GNP and the liquids segments as we think about the basin.
Okay, great. Thank you and just one quick follow up.
A little bit more into Capex, what goes into that upside downside for the Capex range, what the sensitivities are there.
And could you potentially provide some color on the components or segment level spend.
The majority of that spend specifically allocated to.
We're not going to get into segment by segment, but like Walt mentioned in his remarks, you know, we're we're finishing up MB five we've got M. B, a pretty significant amount of the MB six spend that will occur in 'twenty three.
And then the uptick in activity when you think about the step up in well connects.
In both the mid continent, and the Bakken that's going to drive some additional cash.
Capital needs from a well connect little horsepower many dead some pumps here, they're in the NGL segment those types of things, but those are highly highly efficient capital and typically generate very strong returns. So those are the types of things that we've seen and then also we're seeing we've got some of those tie.
Projects in the gas pipeline segment as well that we're finishing up when we talked about our storage and in some other some other expansion opportunities.
Got it. Thank you I appreciate the color.
The next question comes from Neal Dingmann with Chewy Security. Please go ahead.
Hey, good morning, guys.
At a higher level, we've seen some of the public e&ps.
Gobble up some of the.
Private companies and then kind of slow their pace of activity down. So I was just wondering if you could maybe talk about any exposure you have public versus private or or any observations you have seen if maybe one of these deals that happened with your assets.
Neil This is Kevin.
No, we really havent seen the impact and in some cases, we've seen it go the other way a little bit where maybe some of the larger publics have shed some of the acreage that they may be considering more tier two tier three and we've seen companies that acquired it go ahead and start drilling.
So that's been a little bit of a phenomenon but.
We have been we've seen very consistent investment from the large publics that we have and we've kind of got the who's who of especially in the Bakken.
But also in the mid continent, there they've been they've been incredibly consistent with the capital that's been allocated to those basins.
Alright, that's a great point on the flip side of that and then.
For my for my follow up.
The pier B one of the large operators, who has kind of said they were shifting to the Maui, which comes bring a much higher gas cut but I just wanted to check and see if you were you seeing is that what youre seeing or is that what you're planning for or is the kind of guidance for the Rockies more so about the Bakken growth and maybe the PRP Justice.
<unk>.
Moderate growth.
Yeah.
The last is what has had the way we think about it we've got a nice position in the G&P segment, we do have a very nice large position in.
In our NGL business.
There's been several operators out there that have talked about the powder and spending more capital.
So we do have some modest growth built in but the driver of the Rockies volumes is going to come from the Bakken.
That's perfect. Thanks, guys.
The next question comes from Neel Mitra with Bank of America. Please go ahead.
Hi, Good morning, I wanted to touch on the implications of the building M B six to essentially replace Medford.
I'm, assuming that you're gonna flow less purity volumes on Sterling and transition more to a Y grade down to Belvieu on Arbuckle and I wanted to know the runway for our buckle on latent capacity before you'd have to consider an expansion for that.
<unk> volumes.
Yeah.
Neil This is Sheridan.
Yeah, Youre right as we put in <unk> six.
Whereas we're moving raw feed today, we're not moving as much purity products on on the Sterling system.
As it comes to expanding our buckle too we as we did with other pipes, but in a large diameter pipeline.
If we need more capacity, it's a very easy to put in a couple more pump stations and we get hundreds of thousands of barrels more of capacity on that pipeline and obviously, we are watching that and we can react very quickly. So it's fair to say, we will not run out of raw feed capacity to Mont Belvieu from the mid call. It.
Got it great and then the second question related to that when you look at optimization opportunities, obviously, you'll be Uh huh.
Have less capacity in Conway.
And sometimes you're short propane in that market and you.
You have the ability to send natural gasoline up to Canada, how does the.
Higher capacity and in Belvieu versus Conway impact the optimization revenues going forward. After you get the insurance proceeds.
Neil as we look at that it's going to change it a little bit, but I don't know from a from a financial impact it's going to have that big of a big of an impact we as we went back and looked at it as we determined whether or not we were going to build met for back or do the N V. Six we noticed that most of the volume from that Bert already flows.
Mont Belvieu on average.
And so I think I also look at it is this just going to put us back in a position by moving <unk> down there. The way we were before we did put in the Bush and fractionator in O eight.
The Bushnell fractionator today has enough volume to satisfy the Midtown market with it with it while it has there.
We've transitioned our business to be a little bit more belvieu anyway. So I think as we will be able to take advantage of probably.
Probably spikes in the Conway market, a little bit more.
And we have in the past and we'll be able to move optimized through all raw feed system down to the down to the fractionator in Mont Belvieu. So all in all I don't think it's going to be that big of an impact on our optimization business.
Okay. Thank you that's great color.
The next question is from Robin ready with J P. Morgan. Please go ahead.
Hey, guys. Thanks for taking my question today.
Start off kind of a two parter on the volume outlook I was wondering if you could provide a breakdown of that 10% G&P inlet growth assumption of 23 between.
The mid Con in Bakken and then the second part of that question was kind of what's the right way to think about volumes and EBITDA growth in 'twenty for if you guys have 20 plus rigs on your acreage for two to three years.
I think we did provide the the breakdown by mid continent versus Rockies in the materials for the guidance range for 'twenty three so that that's in the materials.
As we think about the growth we've mentioned that it takes roughly 15 rigs on our acreage to hold volumes flat. So clearly if were sitting north of 20 rigs on our acreage in those rigs stay there we're gonna experienced growth.
And that would include growing 2024 over 'twenty three if the activity levels remain kind of where they're at today in the Bakken and that would also hold true for the mid continent as well.
You've also got the rising gas to oil ratios. So as we move through time the gas to oil ratios have continued to trend up which is also going to be a tailwind for volume growth as we especially if we're keeping these activity levels.
Got it appreciate that and then I appreciate that you guys spoke on frac fees a bit earlier, but I'm. Just wondering if maybe you guys could provide a rough sense of what third party frac fees look for look like per quarter in 'twenty three and then maybe for 2024 as well given like the incremental volume growth maybe can.
Can we think about third party frac fees in the hundred million range for 'twenty four.
Yeah.
Yeah, I don't we're not going to break down our factories just for competitive reasons I don't have it go through 'twenty three but it's very to say that what we've got from the insurance company is going to cover what we're gonna pay to third party fracs.
I'm doing great.
And 24 got it.
Got it thanks for calling.
Today's last question comes from Sunil Sibal with Seaport Global Securities. Please go ahead.
Yeah, Hi, good morning, and thanks for all the clarity just wanted to confirm one thing with regard to your comments on the Mexico section there too I.
Thank you mentioned that you considered that to be fully contracted so is it fair to assume that.
You know all your third party frac needs for 'twenty to 'twenty three on corn, you already sort of all kind of contracted at this point of time.
Yes, yes, that's a good assumption.
Okay. Thanks for that and then Oh on the supply of the gas pipeline.
In addition to the four pool I was curious you know what are the kind of gating items for that project.
And could you look at you know it was kind of a JV or a partnership for that pipeline.
And then lastly, you know would you look to finance all of that if that were to move ahead on your balance sheet or you could look at some of the other ways to finance.
So Neil this is Kevin I mean, we're still again early in the process from from the pipeline perspective, it would be.
Intra state pipeline, so we wouldn't need other FERC approvals as it relates to actually building the pipeline if it did.
<unk> F I D.
As far as partnerships go you know we are looking at it is we would own the pipeline at this point, but as with anything if there's a strategic and economic reason for us to have a partner we would consider that.
But but again at this point, we're approaching it like we're gonna that our pipeline would just be part of that entire pipeline service that would get gas to the Gulf coast or excuse me get gas to the west coast.
Of Mexico.
Got it and then on the financing side.
On the balance sheet.
Yeah.
So does this pipeline is going to be built over a course of several years in the context of our normal capex.
We would just do it on our balance sheet, unless we found attractive.
Attractive source of capital that was more efficient than the normal way, we always are keeping our eyes open for that sort of thing but.
I don't think it would have.
A significant change in our Capex program.
Going forwards.
One that we would have to change our ordinary course.
Understood. Thanks for all the color.
This concludes our question and answer session I would now like to turn the conference back over to Andrew go off for any closing remarks.
Alright. Thank you all our quiet period for the first quarter starts when we close our books in April and extends until we release earnings in early May we will provide details for that conference call. At a later date. Thank you again and have a good day.
Yeah.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
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