ONEOK, Inc. (NYSE:OKE) Q4 2022 Earnings Call Transcript

ONEOK, Inc. (NYSE:OKE) Q4 2022 Earnings Call Transcript February 28, 2023

Operator: Hello, and welcome to the ONEOK Fourth Quarter 2022 Earnings Conference Call. . Please note, this event is being recorded. I would now like to turn the conference over to Mr. Andrew Ziola. Please go ahead.

Andrew Ziola: Thank you, MJ, and welcome, everyone, to ONEOK’s 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 ONEOK’s expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. . With that, I’ll turn the call over to Pierce Norton, President and Chief Executive Officer. Pearce?

Pierce Norton: Thanks, Andrew, and good morning, everyone, and thank you for joining us this morning. On today’s call is Walter 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 Kelley, Senior Vice President, Natural Gas Pipelines. Yesterday, we announced strong fourth quarter and full year ’22 performance. We met our 2022 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 have positioned ONEOK to continue delivering growth in 2023. I believe the term resiliency is a great description descriptor of 2022 and will continue to be a focus of our operations going forward. Our people, assets and earnings continue 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 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 are key differentiators of ONEOK’s 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 supply 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 3.5x and significant — a significant milestone for us. We provided investors with more than 25 years of 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 continue 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 is a source of pride for ONEOK and is a key metric for evaluating our management’s team performance annually. Our nearly 15% ROIC 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 will continue.

Finally, the continued demand of the energy products and services that we provide, which are vital to our national security and the quality of life, in which we believe will play an important role in a transforming energy future. U.S. 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 a year of solid financial and operational performance. And as you can see, there are many reasons why we are confident and optimistic about ONEOK’s future. With that, I’ll turn the call over to Walt for a discussion of our financial performance.

Walter Hulse: Thank you, Pierce. As we detailed in yesterday’s press release, we expect continued growth in our businesses in 2023 after achieving our 2022 financial guidance even with some challenging events. ONEOK’s 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. 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 $0.95 per share or $3.82 per share on an annualized basis, marking a return to dividend growth following 3 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 3.46x, in line with our previously discussed aspirational target of 3.5x 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 and adjusted EBITDA midpoint of $4.575 billion. Our guidance includes the net effect of the onetime insurance settlement gain of $780 million and future method 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-5 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 $4.575 billion adjusted EBITDA guidance midpoint for 2023. Excluding the effect of the settlement and the third-party costs of $540 million, this 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 midpoint for both natural gas liquids and natural gas gathering and processing segments driven by higher volume expectations across our operations.

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Kevin will provide more detail on each of the operating segments in a moment. Our 2023 guidance assumes producer activity associated with WTI crude oil prices in the range of what we are currently seeing 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 MD5 early in the second quarter of 2023 and also more than $300 million related to MD6 this year. Excluding the MD6 expenditures, our total CapEx would have been lower than 2022. Our 2023 CapEx guidance does not include the Saro 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 AMT to have an impact on our cash taxes beginning with the 2024 tax year. You can find details in our 10 -K when it is filed later today. I will now turn the call over to Kevin for a commercial update.

Kevin Burdick: Thank you, Walt. 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.

Our Natural Gas Pipelines segment exceeded its 2022 financial guidance range on higher earnings from long-term storage services and higher rates from renegotiated contracts customers continue to see the value in our storage assets, and we continue to evaluate opportunities to expand these services. Turning to 2023. A 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 midpoints, 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.

In the natural gas liquids segment, we expect volume growth to be driven by strong producer levels, a producer activity across our operations, a continuing the momentum we saw from producers in 2022. Higher average fee rates will also contribute to the segment’s earnings as contract escalators continue to be realized throughout the year. NGL market dynamics point toward a continued improvement in global demand with China reopening and with lower natural gas prices, resulting in an attractive environment for U.S. pet chems. 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 also expect to continue to see opportunities to incentivize ethane recovery in the Rocky Mountain region this year. We are on track to complete our 125,000 barrel per day MB-5 fractionator in Mont Belvieu early in the second quarter of 2023. And we recently announced MB-6 which we expect to be complete in the first quarter of 2025. Moving on to the natural gas gathering and processing segment. We expect volume growth again this year in both the Rocky Mountain 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 a 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 Demicks Lake III 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 and 22 completion crews operating in the basin 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 a 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 DUCs basin-wide with approximately half on our acreage. Keep in mind that in the Bakken, producer economics are driven by crude oil and customers — our customers are 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 continue 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 process volumes to grow 12% at our guidance midpoint compared with 2022 and average more than 700 million cubic feet per day in 2023. Rig activity across the basin will also continue to drive additional NGLs to our system. In the natural gas pipeline segment, we continue to expect strong demand for natural gas storage and transportation services in 2023. At the end of 2022, nearly 80% of our natural gas storage capacity was contracted under long-term agreements, and our pipeline transportation capacity was nearly 95% contracted.

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 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, a ONEOK 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 ONEOK intrastate natural gas pipeline called the Swaro Connector pipeline and with a 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 ONEOK pipeline is expected in mid-2023. Pearce, that concludes my remarks.

Pierce Norton: 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. Our company and our industry aren’t immune to incidents, but I’m proud of how we have 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 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 a safe, reliable and environmentally responsible manner 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 are now ready for questions.

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Q&A Session

Operator: . Today’s first question is from Brian Reynolds with UBS.

Brian Reynolds: Maybe to start off on the guidance. Last year, we had a couple of weather events and a material amount of frac capacity come offline, but guidance was still achieved. While some activity seems to have gotten pushed to 23% from ’22, the ’25 guide yearly seems similar to 2022 original base guidance. So perhaps could you just talk about the puts and takes this year from last year and whether this is a base guide out performance or if we saw some volumes for G&P and NGLs get moved into ’23.

Kevin Burdick: Brian, yes, this is Kevin. I think probably the big thing is just like you mentioned the volume that was off-line 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 ’22. But it delayed some of the well connects as we into push back into ’23. So that’s why we feel really good about our ’23 guide. Yes, we’ve got a significant step-up in well connects. But when you look at the wells. We’ve already connected to date, which historically is 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 we’re at volumetrically in both G&P and NGL out of the Bakken.

Brian Reynolds: Great. And as a follow-up just on capital allocation. It seems like we should have pretty stable CapEx in the next few years with the MB-6 build-out. And just given the already announced dividend raise and leverage targets and payout ratios met at this point, how should we think about use of excess cash going forward?

Pierce Norton: Brian, this is a 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 that we want to maintain and grow a — what we refer 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 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 3.5x debt-to-EBITDA.

And assuming that we’ve achieved all of those kind of capital allocation key strategies, if we do have excess cash or whatever, we could consider share buybacks. But that’s kind of laying it out as to what our priorities are from a capital allocation standpoint.

Operator: The next question is from Spiro Dounis with Citi.

Spiro Dounis: First question, I wanted to touch on the third-party frac fees. You guys highlighted Mont Belvieu 5, frac 5 coming online and really sort of benefiting 2024 from the third-party frac 3 perspective. But I guess just given the fact it does come on or it sounds like it could come on early and second quarter, is there any ability to leverage that frac as well in 2023? And to the extent you’ve considered any of that in the ’23 guidance?

Sheridan Swords: Spiro, this is Sheridan. So when we had the Medford incident, we went out right away and secured frac capacity that we thought we needed going into ’23. And we already took into account that MB-5 was going to come up in April. So our — what we contracted for frac capacity is obviously heavier in the first part of the year until MB-5 comes on and then drops off. And that was all accounted for in the settlement that we had with the insurance company. So 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, MB-5 will help us if volume exceeds our expectation, we will be able to use MB-5 for that in ’23.

Spiro Dounis: Got it. Second question, multipart one on the Sao pipeline. So to the extent that does reach FID in mid-’23. I guess, one, would you expect any impact on the ’23 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 cost of the pipeline, if you willing to take on JV partners? And then finally, just on the 2.8 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?

Kevin Burdick: Spiro, this is Kevin. Still a lot of your questions were — that’s what we’re working through right now. We’re not going to provide a capital guide. There would be a little money that would be spent if we FID this year. But obviously, the bulk with it coming on, the anticipation had come on. And 2025 time frame, most of the capital is going to get pushed — is going to be pushed out.

Operator: The next question comes from Michael Blum with Wells Fargo.

Michael Blum: So I wanted to ask about ethane recovery. You 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 and what is actually reflected in guidance?

Sheridan Swords: Yes, Michael, this is Sheridan. We have a very modest amount of ethane incentivized ethane in our guidance, a little bit that we have already contracted 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 ’23 with this low gas price which Kevin mentioned in his remarks, is making the United States pet chem 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, which 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 at wider spreads than what we have done today.

Michael Blum: Okay. Great. And then I also just wanted to ask another question about the frac market. It seems like everyone is adding frac capacity. And so I’m wondering if you think that’s going to be pressuring rates over time at Mont Belvieu and within that context, how should we think about frac 6, how much of that is going to be contracted with third parties versus held-on account?

Sheridan Swords: The — Michael, what I’d say about frac capacity coming online. In the NGL world, the 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’d probably see the spot market be a little bit weaker than it was when our frac went down. But long term, those fracs are contracted and as volume comes on, they will fill that. In terms of MB-6, remember, MB-6 is really just replacing Medford. And so MB-6 is completely contracted as Medford was completely contracted. So we’re really only looking at our really add to our frac fleet is the MB-5 that we had substantially contracted before the Medford incident. So I think you’ll 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.

Operator: The next question comes from Harry Mateer with Barclays.

Harry Mateer: On the 3.5x leverage target, Walt, you’ve spoken about it as being aspirational for some time. But at this point, with out ’22 and given your ’23 guidance, it seems 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 with Sahara ahead of you? And what is still a pretty good oil price environment?

Walter Hulse: Well, Harry, I think that we’ve definitely achieved the goal as we sit here today, given the fact that we had an $830 million 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 MB-6. And we would expect to come back into that 35% or below in the not-too-distant future. We like that as a spot to give us flexibility going forward. But I think the peers walk through our capital allocation thoughts earlier. 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 allocation.

Harry Mateer: Okay. And then my follow-up is just — I know you guys recently redeemed one of your maturities later this year. You have another one. Any guidance you can give us on potential financing plans for the year and how are you planning to manage potential debt capital markets needs.

Walter Hulse: Sure. Well, yes, you’re right, that we actually did the make call because we could do it at par on the 4.25% for May. The other coupon that we have later in the year is 7.5%. So the make hall doesn’t work. So we’ll wait until the actual contractual call date, which I think the first time we can do that is early May. 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 there is a need for any further issuance. But as we sit today, we will cover off our maturities with cash on hand.

Operator: Next question is from Jackie Caleres with Goldman Sachs.

Unidentified Analyst: First, I’d like just to focus a little bit on the macro front. What are your thoughts on comfort level on backing egress out of the basin? And further, are you seeing the need for Bison River, any other ways to add gas capacity there?

Kevin Burdick: Jackie, this is Kevin. Just kind of macro Bakken related from a gas takeaway perspective. We’ve talked before that we do believe there’s still 300 million, 400 million cubic feet a day of capacity on Northern Border that the basin will continue to price out. So in other words, displaced gas currently flowing down from Canada, there has been a 100 million a day roughly project that’s kind of moved south and southwest over to — on WBI and gets down into a 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 TC Energy has said they’re working that project and have been pleased with the results so far. So there’s an opportunity. So from an egress perspective, we feel good, obviously, for the next — that will get you several years out even with 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 we’re talking about. So Basin 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. The rigs that are there today, when you also look at the — finishing up some DUCs they’ve got we’re in really good shape to meet the volume guidance in both the G&P and the liquids segments as we think about the basin.

Unidentified Analyst: Okay. Great. And just one quick follow-up. A little bit more into CapEx. What goes into that upside, downside for the CapEx range? What’s is are there? And could you potentially provide some color on the components or segment-level spend? What’s the majority of that spend specifically allocated to?

Kevin Burdick: We’re not going to get into segment by segment. But like Walt mentioned in his remarks, we’re finishing up MB-5. We’ve got MB a pretty significant amount of the MB-6 spend that will occur in ’23. 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 capital needs from a well connect little horsepower, many deaths and some pumps here or there 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 type projects in the gas pipeline segment as well that we’re finishing up when we talked about our storage and some other expansion opportunities.

Operator: The next question comes from Neal Dingmann with Truth Securities.

Neal Dingmann: 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 any observations you’ve seen if maybe one of these deals that happened with your assets?

Kevin Burdick: Neil, this is Kevin. We really haven’t 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 2, Tier 3, 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, especially in the Bakken, but also in the Mid-Continent, they’ve been incredibly consistent with the capital that’s been allocated to those basins.

Neal Dingmann: All right. That’s a great point on the flip side of that. And then for my follow-up, in the PRB, one of the large operators has kind of said they were shifting to the Mowry, which comes — brings a much higher gas cut. I just wanted to check and see if you are you seeing — is that what you’re 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 PRB just assumes moderate growth?

Kevin Burdick: Yes. The last is what is 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 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.

Operator: The next question comes from with Bank of America.

Unidentified Analyst: I wanted to touch on the implications of building MB-6 to essentially replace Medford. I’m assuming that you’re going to flow less purity volumes on sterling and transition more to Y-grade down to Bellevue on Arbuckle. And I wanted to know the runway for Arbuckle on latent capacity before you’d have to consider an expansion for the increased volumes?

Sheridan Swords: Neil, this is Sheridan. Yes, you’re right. As we put MB-6 or as we’re moving raw feed today, we’re not moving as much purity products on the Sterling system. But as it comes to expanding Arbuckle II, we, as we did with other pipes, put it in a large diameter pipeline that if we need more capacity, it’s very easy to put in a couple of 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-Continent.

Unidentified Analyst: Got it. Great. And then the second question related to that when you look at optimization opportunities, obviously, it will be — have less capacity in Conway and sometimes you’re short propane in that market. And you have the ability to send natural gasoline up to Canada. How does the higher capacity in value versus Conway impact the optimization revenues going forward after you get the insurance proceeds?

Sheridan Swords: Neil, as we look at that, it’s going to change a little bit, but I don’t know from a financial impact, it’s going to have that big of an impact. We — as we went back and looked at it as we determined whether or not we were going to build Medford back or do MB-6, we noticed that most of the volume from Medford already flows to Mont Belvieu on average. And so I think I also look at it as this is going to put us back in a position by moving MB-6 down there the way we were before we did put in the Busan fractionator in ONEOK. The Busan fractionator today has enough volume to satisfy the mid-continent market what the deployment has there. We’ve transitioned our business to be a little bit more Bellevue anyway. So I think as we’ll be able to take advantage of probably spikes in the Convoy market, a little bit more than we have in the past, and we’ll be able to move — optimize the overall feed system down to the fractionators 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.

Operator: The next question is from Robin Reddy with JPMorgan.

Unidentified Analyst: To start off kind of a 2-parter on the volume outlook. I was wondering if you could provide a breakdown of that 10% G&P inlet growth assumption in ’23 between the Mid-Con and Bakken. And the second part of that question was kind of what’s the right way to think about volumes and EBITDA growth in ’24 if you guys have 20-plus rigs on your acreage for 2 to 3 years.

Kevin Burdick: I think we did provide the breakdown by Mid-Continent versus Rockies and the materials for the guidance range for ’23. So 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 we’re sitting north of 20 rigs on our acreage and those rigs stay there, we’re going to experience growth. And that would include growing ’24 over ’23 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.

Unidentified Analyst: Got it. Appreciate that. And then I appreciate that you guys spoke on frac fees a bit earlier, but just wondering if maybe you guys could provide a rough sense of what third-party frac fees look like per quarter in ’23 and then maybe for 2024 as well given like the incremental volume growth maybe could we think about third-party frac fees in the $100 million range for ’24?

Sheridan Swords: Yes. I don’t — we’re not going to break down our factories just for competitive reasons on how we go through ’23. But it’s very to say that what we’ve got from the insurance company is going to cover what we’re going to pay to third-party fracs in ’23 and ’24.

Operator: Today’s last question comes from Sunil Sibal with Seaport Global Securities.

Sunil Sibal: I just wanted to confirm one thing with regard to your comments on the Medford fractionator. I think you mentioned that you considered that to be fully contracted — so is it fair to assume that all your third-party frac leads for 2023 and 2024 are kind of contracted at this point of time?

Walter Hulse: Yes. Yes, that’s a good assumption.

Sunil Sibal: Okay. And then on the Saguado gas pipeline, in addition to the FERC approval, I was curious what are other kind of getting items for that project? And could you look at a kind of a JV or a partnership for that pipeline? And then lastly, would you look to finance all of that, if that were to move ahead on your balance sheet or you could look at some other ways to finance.

Kevin Burdick: Sunil, this is Kevin. I mean we’re still, again, early in the process from the pipeline perspective. It would be an intrastate pipeline. So — we wouldn’t need other FERC approvals as it relates to actually building the pipeline if it did reach FID. As far as partnerships go, we are looking at it as 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 again, at this point, we’re approaching it like we’re going to 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.

Sunil Sibal: Got it. And then on the financing side, all on the balance sheet or…

Walter Hulse: Yes. I mean. So 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 an 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 forward. So not one that we would have to change our ordinary course.

Operator: This concludes our question-and-answer session. I would now like to turn the conference back over to Andrew Ziola for any closing remarks.

Andrew Ziola: All right. 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’ll provide details for that conference call at a later date. Thank you again, and have a good day.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.