Operator:

Good day, and welcome to the ONEOK First Quarter 2024 Earnings Conference Call and Webcast. [Operator Instructions] Please note, this event is being recorded.

Andrew Ziola:

Thank you, Megan, and welcome to ONEOK's first quarter 2024 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.

Pierce Norton:

Thanks, Andrew. Good morning, everyone, and thank you for joining us.

Yesterday, we announced first quarter 2024 earnings and increased our full year 2024 financial guidance. Solid results during the first quarter were supported by higher year-over-year volumes in the Rocky Mountain region and contributions from the Refined Products and Crude segment. The efforts of our employees were highlighted once again as we were able to effectively manage through the winter weather during the quarter. Heating degree days were actually higher than normal in January, but it was the temporary acute cold and excessive wind that caused a deviation from normal operations. Volumes have rebounded across our systems, and we are continuing to see volume trends higher, providing additional confidence in our expectations for the remainder of the year. Our increase to 2024 financial guidance was driven by 2 primary key factors:

first, favorable industrial fundamentals across our systems, which is supply and demand, that are contributing to volume growth and providing significant momentum for the remainder of 2024 and into 2025. And second, the continued confidence in our ability to realize meaningful commercial and cost synergies. We remain focused on the integration efforts following the acquisition of Magellan last year, and our management team has spent the past several months meeting with employees and visiting assets across all of our operations. Our employees see the value of our combined businesses and are excited about the opportunities ahead. Through collaboration between business segments and the innovation of our employees, we are on pace to exceed our 2024 synergy goals, while most importantly, putting safety first. We also see growth across our systems from producer productivity, favorable commodity prices and continued demand for our products and services or as we previously mentioned, favorable industrial fundamentals. One potential significant source of future natural gas demand is expected to increase in power generation required to serve AI-driven data centers. ONEOK like other natural gas pipeline operators will play a role. We have already had conversations with several of our large electric power generation customers and power developers, who anticipate the need for additional natural gas transportation to address this future AI data center-related power demand. As the need for future power generation increases, domestic natural gas demand is projected to increase. This is going to affect the entire midstream value chain, and ONEOK is positioned to play a meaningful role. Today, we serve numerous natural gas-fired power plants across our system, and many of those customers are looking to expand, some related to AI and others to address general power demand. We also continue to see supportive demand and fundamentals for the NGLs and refined products across our system. Ethane remains a highly preferred feedstock for the petrochemical facilities, NGL export strengths continue, and a seasonal refined product demand for travel and agriculture is picking up. We remain focused on expanding and extending our systems in ways that align with our customers and the market's needs. ONEOK now larger in scale, will continue to support our efforts to help address domestic and international energy demand, contribute to the energy security of our nation and maintain our critical role in the long-term energy transformation.

Walter Hulse:

Thank you, Pierce. As Pierce mentioned, we increased our 2024 financial guidance expectations. We increased our 2024 net income midpoint to $2.88 billion and increased our adjusted EBITDA midpoint by $75 million to $6.175 billion. This new guidance also brings up the low end of our original range, reflecting the strong fundamentals across our businesses. We remain confident in our synergy expectations. Our updated guidance still assumes we will meet or exceed our midpoint of $175 million in cost and commercial synergies in 2024. We continue to expect that additional annual synergies will meet or exceed $125 million in 2025. Additionally, our total 2024 capital expenditure guidance remains unchanged at $1.75 billion to $1.95 billion.

Jeremy Tonet:

Just want to start off with the guidance increase, if I could, I want to dig into the component pieces there. When you're talking about volumes, it seemed like they rebounded in stronger. Just wondering if you could break down where across the system that is, if that's really the Bakken or other parts of the portfolio, you're seeing better-than-expected strength. And at the same time, you talked about the synergy realization maybe being better than expected or more confidence. And just wondering if you could dig in a little bit more detail on what the component drivers to that are as well?

Pierce Norton:

So Jeremy, this is Pierce. So I think it's kind of all of the above. There's -- we -- if you go back the last 20 years, electrical generation load between things that were added as far as devices that you have to charge versus the efficiencies that we got from LED pipes and those kind of things, pretty much offset one another. So it's been really flat for the last 20 years. Kind of for the first time in a couple of decades, we're seeing a lot of momentum for needing more energy for these data centers. And a natural quick solution to that is natural gas. So we do see that, that's going to increase natural demand here specifically over the next half decade here and probably even more.

Jeremy Tonet:

That's helpful. So on that last point, you're in current conversations with potential customers that could be proximate to your assets, I just want to make sure I have that right.

Operator:

Our next question comes from Spiro Dounis with Citi.

Sheridan Swords:

Yes. Spiro, we are getting more confident in moving up the ladder as we see more opportunities come out there. And we're kind of seeing it all across parts of our business. We're seeing it from as how we optimize our storage, we're seeing it how we are combining the 2 assets to make logistics savings better, we're seeing it as we tie the systems together, how we can demand pull NGLs in the refined products. So we're seeing it across all aspects of our business that we've talked about.

Kevin Burdick:

Spiro, this is Kevin. The other thing I'd just add in there is we pull in all these opportunities that Sheridan talked about, not only there, but also we continue to identify opportunities on the G&A side as well from a cost reduction standpoint. When we pull all that in, we prioritize them. We understand what the value is, the timing, any cost, and then we get people assigned to them. And I think it's that transparency and accountability internally that help us get the confidence of what we're looking at and those numbers continue to improve. Spiro, this is -- the only thing is it's a comment of you get what you measure, and we are measuring our synergies.

Walter Hulse:

Spiro, I'm not going to go down the 2025 guidance route yet. But I think it's fair to say you've identified directly that we've got 3 decent-sized projects that will all roll off early in 2025. So as we look at CapEx going forward, we have much more manageable, lower capital, very high return opportunities that are presenting themselves. So I think it's fair to say that we would see that trend down. And if you were to look longer term for a kind of sustainable CapEx level, it probably is lower than where we are for 2024.

Tristan Richardson:

Maybe just a minor one on the guidance increase. Should we think of the small Saddlehorn acquisition as part of that increase in expectations for the year? And if so, maybe kind of what proportion of the guidance increase could we attribute to the acquisition?

Tristan Richardson:

Appreciate it.

Tristan Richardson:

Helpful context. We appreciate it. And then maybe just more of a housekeeping one. How should we think about maybe the corporate cost allocation? You guys noted a $33 million change within refined products crude. Should we think of all of that is attributable to moving the corporate costs around? Or maybe is there a way to think about for the full year '24, maybe what percent of total corporate costs get allocated to the segment just as we think about refined products and crude modeling?

Operator:

Our next question comes from Michael Blum with Wells Fargo.

Charles Kelley:

Michael, this is Chuck. As far as capacity adds that we could look at along our footprint. As Pierce mentioned a couple of times here today, we are in conversations with existing customers on our pipes connected to little more than -- I think the number is 40 gas-fired generation facilities today. We're working -- there's about 15 potential projects on our systems today. Not all of those will come to fruition, but the conversations are ongoing and of the 15, we're seeing probably 3 or 4 of those folks saying the demand is derived from the data center.

Michael Blum:

Second part was about any upstream benefits.

Pierce Norton:

So Michael, what I would say there is it's going to be a little bit of a longer answer here. But you came at it from the question of what's the capacity of an existing line, and you put more demand on it, and what does that look like. I'll just paint a scenario, which don't take anything from my comments that we're far along in this. But if you were to put a data center in North Dakota, it's a cold weather area. It's very advantageous for data centers, and you connected it, say, to the tailgate of one of the plant.

Michael Blum:

Okay. Perfect. And then just wanted to go back on Saddlehorn for a second. I realize it's a small acquisition in the grand scheme of things, but I wonder if you can just talk in terms of strategic rationale for that asset to why you want to own more of it? And just also from a capital allocation perspective, and why that makes sense?

Operator:

Our next question comes from Theresa Chen with Barclays.

Sheridan Swords:

Theresa, this is Sheridan. Yes, we do see -- we've always, from the beginning, saw opportunity in marketing crude oil to bring volume to our system. Specifically, right now, as we think about what's going on in the next 2 months, with the [indiscernible] differential kind of blowing out, we're naturally seeing more volume come to BridgeTex.

Theresa Chen:

Got it. And going back to the AI theme, this has come up so much in recent weeks and months, but related to natural gas transmission and storage assets. And I'm just wondering if you have any early indications or thoughts on just quantitatively, what this could mean as far as the size of the EBITDA opportunity for ONEOK?

Operator:

Our next question comes from Sunil Sibal with Seaport Global Securities.

Sheridan Swords:

This is Sheridan, again. On growth projects, we are continuing to, on the synergy side, continuing to see low capital/high multiple type growth projects that we are baking in as we continue to go forward. They're coming all the time. We get more and more of them, but they're kind of factored into our overall capital plan already. [indiscernible] that we would capture this. But we continue to get more excited about that growth that we see different growth projects as it relates to synergies and bringing them together.

Charles Kelley:

I think as you were asking, I think what you're asking about the interest rates. We aren't a company that relies heavily on short-term debt. All of our debt has termed out. And we have cash called the last 3 bonds that we had matured. And we've said that we expect that, that will probably be the case later this year that we would go down that path. So occasionally, we're in and out of the CP market to cover month-to-month type of things. But our business is generating cash flow to be self-contained, and so we don't see any real impact from higher rates going forward.

Sheridan Swords:

Yes, on the Permian [indiscernible] sequential in the Permian is really weather. We had the impact of weather out there. And one thing we noticed in the Permian, they're not used to weather. And any time they get any kind of weather, it takes them a little bit more to get back up and going. So we saw some weather impact the first quarter and it was a big reason for the volume decrease. As we think about contracting going forward on our West Texas pipeline expansion, it is going as we had planned. We continue to contract more volume on that.

Operator:

Our next question comes from Neil Mehta with Bank of America.

Sheridan Swords:

Neil, this is Sheridan. The first thing on your increase on the earnings on the fee rate. A lot of that is driven by our inflationary escalators that are coming in. And to a lesser extent, volume coming from certain customers that may have a different fee structure in there. And yes, we do think that will continue going forward, that fee rate. On the volume cadence coming out of the Bakken, it can be a little bit lumpy as we bring on compressor units and everything else.

Neil Mehta:

Got it. And then I wanted to clarify on the AI theme. I know this is still very early innings. But curious, I wanted to follow back up on kind of the opportunity you see there in North Dakota with the advantageous weather temperatures, et cetera. Are you seeing opportunities from the wellhead to move lines to CCGTs or more so from CCGTs to data centers? And is this kind of geographically concentrated with your opportunities within your NGL footprint in the Bakken? Or are you seeing things outside of the Bakken and perhaps the Permian and Mid-Con as well?

Keith Stanley:

First, just a follow-up to Neil's question, but on the Rocky's NGL bundled rate, that was up nicely to $0.30 in Q1. What drove that higher? And is that a good run rate for the balance of the year?

Keith Stanley:

Okay. Great. Second question just on going back to Saddlehorn, but are you optimistic that you could find other bolt-on type opportunities like that over the course of the next year, or was that more of a one-off with Western's process? I noticed you didn't list acquisitions as part of the capital allocation priorities in your remarks?

Operator:

Our next question comes from Neil Dingmann with Truist Securities.

Sheridan Swords:

Neil, could you repeat that question one more time?

Unknown Executive:

On our raw NGL volumes. One of the big things on the raw feed NGL volumes that's going to make it go up is ethane recovery. And we've come out and said that we're going to have -- naturally the rockies is going to be in rejection, but we're going to have opportunities to incentivize that. And I also said we're going to manage our capacity in our pipeline at Elk Creek until we get the expansion on, is up more to the high end of its capacity. Then you have the Mid-Continent, where we have said that's going to be kind of in and out of ethane recovery. So is that more -- we have the opportunity to -- as prices spreads stay wide like they kind of are today, we'll see more ethane throughout the year come out, which will drive that up, your raw fleet throughput up.

Neal Dingmann:

Very helpful. And then just a second question on your natural gas pipeline earnings, I'm just wondering, part I saw of the sequential increase was driven by that earnings was driven by the higher natural gas sales volumes previously held in inventory. I'm just wondering, is that something you anticipate to continue to see potential upside from these incremental volumes in inventory? I mean is there -- is that more to come, or what should we think about with other volumes around associated around that?

Operator:

Our next question comes from Craig Shere with Tuohy Brothers.

Sheridan Swords:

Craig, what I'd say right now is we -- in the incentivized ethane that we've done so far this year, it has been at or maybe a little bit above what we've done, what you'd say more as a run rate in the past. A lot depends on not just the price of ethane, which we have good demand for ethane on the Gulf Coast, but also what the price of natural gas is in the Bakken. And so you got to look at the spread between those 2. But so far, we have been very pleased with what we've been able to incentivized ethane in it.

Sheridan Swords:

Well, I take the last one. On the Conway to Belvieu spread. That has -- actually, we have had opportunities. If you look at the average through the month, it may be [indiscernible] we've had some opportunities to lock in some fairly good spreads. And our system is set up that we can lock in by component Conway to Belvieu or Belvieu to Conway. We can lock both of those in as we go forward. We've been happy where the spreads have been at this time. Obviously, we'd always like them to be a little bit wider, but we've been able to take advantage of them.

Craig Shere:

And I'm sorry, what did you say about thoughts about ethane into next year?

Andrew Ziola:

All right. Well, thank you, everyone. Our quiet period for the second quarter starts when we close our books in July and extends until we release earnings in early August. We'll provide details for that conference call at a later date. Thank you again, and have a great day.

Operator:

Good morning and welcome to the ONEOK Fourth Quarter 2023 Earnings Conference Call and Webcast. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Andrew Ziola, Vice President, Investor Relations. Please go ahead.

Pierce Norton:

Thanks, Andrew and good morning, everyone and thank you for joining us this morning. On today’s call is Walt Hulse, the Chief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development; and Sheridan Swords, who is our Executive Vice President, Commercial Liquids and Natural Gas Gathering and Processing. Also available to answer your questions are Chuck Kelley, our Senior Vice President, Natural Gas Pipelines and Kevin Burdick, who is the Executive Vice President of Chief Enterprise Services. Record volumes, strong financial performance and the closing of the Magellan acquisition solidified 2023 as a year of significant growth and transformation for ONEOK. Momentum from our operations in 2023 is setting the stage for additional growth in 2024. With our earnings release yesterday, we reported double-digit NGL and natural gas processing volume growth year-over-year and continued fee-based earnings growth in all three of our legacy business segments. We also provided 2024 guidance along with some insight into 2025 and beyond, including an expectation for double-digit adjusted EBITDA growth in 2024. Walt will provide more detail on our guidance, which is underscored by solid business fundamentals, demand for the products that we deliver, and a full year of earnings contribution from our refined products and crude oil segments and the initial realization of acquisition-related synergies. Before I turn the call over to Walt, I want to share a few data points that help sum up the exceptional growth ONEOK has experienced in recent years. While our business continues to transform and to look to the future, it’s still important to reflect on what has already been accomplished. I’ll share just a handful of highlights, but there are many more. First, 2023 marked ONEOK’s 10th consecutive year of adjusted EBITDA growth throughout various commodity cycles. Over the same time period, we have increased dividends paid to $3.82 per share from $1.48 per share, a more than 150% increase. And in January, the Board approved another increase. Our volumes out of the Rocky Mountain region have set numerous records. Over the last 5 years alone, NGL volumes from the region have grown at a more than 20% annual growth rate and natural gas processing volumes have grown at a 10% annual growth rate. We have continued to expand our asset portfolio, increasing our extensive pipeline network to more than 50,000 miles from approximately 30,000 miles in 2013 and adding nearly 2 Bcf per day of natural gas processing capacity and 3 fractionators. And finally, through all of this growth, both internally and by acquisition, we’ve continued to prioritize safety and our sustainability and ESG-related performance, consistently ranking towards the top of our industry peer group, including a AAA rating from MSCI. We have achieved a great deal in recent years. And over the course of our company’s history and now with a more diversified portfolio of assets, we are even better positioned to make the most of future opportunities. With that, I’ll turn the call over to Walt.

Sheridan Swords:

Thank you, Walt. We saw strong year-over-year volume growth in 2023 with natural gas processing volumes up 14% and NGL volumes up 10% compared with 2022. Rocky Mountain region volumes were particularly strong with double-digit growth in both NGL and natural gas processing volumes year-over-year. Higher producer activity levels, increased well connects, and continued strong gas-to-oil ratios drove record fourth quarter volumes totaling nearly 400,000 barrels per day of NGLs and nearly 1.6 Bcf per day of processed volume. Mid-Continent process volume increased 15% year-over-year and Permian Basin NGL increased 19% year-over-year, both benefiting from solid producer activity throughout the year in those regions. Well connects across our operations increased more than 50% compared with 2022. We continue to see the benefit of those connections throughout 2024 as volumes ramp. Our Natural Gas Pipeline segment significantly exceeded its 2023 financial guidance range on higher earnings from long-term storage services and higher rates from negotiated fee-based contracts. Our Refined Products and Crude segment adjusted EBITDA totaled more than $420 million in the segment’s first full quarter of operations since the acquisition of Magellan. This segment’s performance was driven by midyear tariff increases, longer haul refined product shipments and steady crude oil transportation volumes. Our optimization and marketing activities, which includes liquids blending also benefited from strong margins and volumes. Turning to 2024. Key drivers for our higher 2024 guidance includes stable producer activity and continued production efficiency improvements, providing strong natural gas and NGL volumes across our systems. Solid refined products demand, continued strength in fee-based earnings and rates and our first full year of annualized synergies. In our Natural Gas Liquids segment, we expect higher year-over-year adjusted EBITDA and raw feed throughput volumes should be driven primarily by growth out of the Rocky Mountain region. Despite lower assumptions for incentivized ethane recovery in 2024 and a low margin contract expiration from Overland Pass pipeline in November of 2023, we still expect higher year-over-year NGL volumes. The expired contracts volume is being replaced with higher rate barrels ramping through 2024. Healthy demand for ethane from the petrochemical industry and wide gas-to-oil ratios are setting up a positive backdrop for NGL markets in 2024. On our system, we’ve assumed high levels of ethane recovery continue in the Permian Basin in 2024 and partial recovery in the Mid-Continent. We also expect to see continued opportunities to incentivize ethane recovery in the Rocky Mountain region. As Walt mentioned, we’ve officially moving forward with the expanding the Elk Creek pipeline to 435,000 barrels per day, increasing our total NGL capacity out of the Rocky Mountain region to 575,000 barrels per day. This additional capacity will support future growth and increased ethane recovery. Moving on to the Natural Gas Gathering and Processing segment. We expect volume growth in the Rocky Mountain and Mid-Continent regions driven by higher-than-anticipated well connections in 2023 and consistent producer activity levels expected in 2024. In the Rocky Mountain region, we expect processing volumes to grow 9% at the midpoint compared with 2023 and an average more than 1.6 Bcf per day in 2024. This outlook includes the impact from the weather we experienced so far this year, including well freeze-offs in mid-January when the wind chills dropped below negative 60 degrees. By the end of January, volumes had recovered to levels achieved prior to the extreme cold. Strong producer activity levels in 2023 and the continued trend of high gas-to-oil ratios drove several months of record North Dakota natural gas production with the latest record of 3.52 Bcf per day set in December. Producer activity has carried over into 2024. Even through the winter months, as we enter March, there are 36 rigs in the Williston Basin with 20 on our dedicated acreage. Through detailed planning sessions with our customers, we expect additional rigs to return as we move into spring. Additionally, we continue to see a trend at producers drilling longer laterals in the basin, 3 miles in length or more as opposed to the historical 2-mile laterals. These longer laterals continue to drive improved production efficiencies and result in fewer well connections needed to grow gathered volumes. As detailed in our earnings presentation, we expect 3-mile laterals to account for approximately 30% of the wells drilled on our acreage in 2024 compared with only 7% 2 years ago. In the Mid-Continent region, we are currently seeing approximately 45 rigs in Oklahoma with 6 operating on our acreage. We expect processing volumes to grow approximately 3% at our guidance midpoint compared with 2023 and average approximately 770 million cubic feet per day in 2024. Rig activity across the basin will continue to drive additional NGLs to our system. In the Natural Gas Pipelines segment, we continue to expect strong demand for natural gas storage and transportation services in 2024. At the end of 2023, more than 75% of our natural gas storage capacity was contracted under long-term agreements, and our pipeline transportation capacity was nearly 96% contracted. We expect similar levels in 2024. From a natural gas storage perspective, we continue to focus on expansion projects. We are currently working on a project to reactivate 3 Bcf of previously idled storage in Texas and are further expanding our injection capabilities in Oklahoma. In February 2024, the FERC approved the Saguaro Connector Pipelines presidential permit, and we expect the final investment decision on the pipeline by midyear 2024. Moving on to the Refined Products and Crude segment. We continue to expect healthy business fundamentals and the segment’s more than 85% fee-based earnings to drive consistent performance. We’ll see the full year effect of higher refined products tariff rates, driven by the midyear 2023 increase of 11.5%. And we expect additional mid-single-digit increases in July 2024. We also expect an increase in refined products volumes, including a benefit from the completion of our expansion to El Paso. Additional benefits are expected from higher volumes and margins related to liquids blending in 2024, driven by favorable market conditions and synergy-related opportunities. Walt discussed commercial synergies earlier, which we expect primarily to show up in our Refined Products and Crude segment’s earnings. Pierce that concludes my remarks.

Operator:

[Operator Instructions] The first question comes from Brian Reynolds with UBS. Please go ahead.

Sheridan Swords:

Well, you’re right, we do see some upside to our synergies be going forward, as we say in the $700 million. And really, a lot of it is going to be driven by being able to bring our refined product and crude oil and NGL systems together, which we have multiple opportunities in many different areas of our systems. And really, as we continue through ‘24 and ‘25, the thought is going to be, as we said before, in prioritization of which ones we’re going to work and we can bring forward. We started 24 wells to be driven by, we’ve reached a substantial amount of our cost saving synergies already through ‘23, and we’ll see a full year of that in ‘24.

Brian Reynolds:

Great, thanks. Appreciate that. Maybe to switch to just the updated return on capital framework. You outlined a 3% to 4% dividend growth, but kind of updated it with the updated payout ratio of 75% to 80% with buybacks and dividends. So looking at the model, it seems like it’s pretty clear on 2024 that you can kind of come to that conclusion. But when I look at ‘25 and ‘26, leverage trends below 3.5x, you should have some excess cash based on existing projects that are FID at this point with potentially Saguaro going into that bucket. So as we look in ‘25 or ‘26, can you maybe update us on how we should think about the return of capital framework. Could we see maybe an increase of buybacks? Or how should we think about maybe interest in M&A or maybe other projects that may come to fruition in ‘25 and ‘26, maybe keep kind of that return on capital framework unchanged.

Brian Reynolds:

Great. Makes sense. Super helpful. Enjoy the rest of the morning.

Operator:

The next question comes from Neel Mitra with Bank of America. Please go ahead.

Sheridan Swords:

Well, in MB-6, as we said in our prepared remarks and in our earnings release, come up in the first quarter of 2025, and it’s 125,000 barrel a day frac. So it will have a significant impact to our third-party frac costs. Our third-party frac costs in 2024 will be about $30 million a quarter, so I think, of what we’ve estimated on that piece. So we’ll be needing third-party frac costs through the remainder of that, which most of we’ve already contracted.

Sheridan Swords:

For commercial reasons, we won’t get into too much of it, but butane blending is driven by regulations of RVP into the gasoline. So there is a limit. But other than that, we don’t want to get too much into it due to commercial sensitivities on what we’re doing.

Operator:

The next question comes from Sunil Sibal with Seaport Global Securities. Please go ahead.

Pierce Norton:

Sunil, this is Pierce. The really question kind of falls in the bucket of mergers and acquisitions, I think – I just want to reemphasize that our primary focus is to continue to be integrating the Magellan acquisition and executing on the synergies and opportunities that we see to create the maximum value for our shareholders. So we’re going to be – we’re going to continue to be intentional and disciplined in our approach to M&A. But I’d also say that we have – and we will continue to look at other mergers and acquisitions in the context of how do they strengthen our competitive position.

Pierce Norton:

So I’ll kind of take a high-level cut at that, and then I’ll ask either Walt or Sheridan to chime in on this. But one thing that I don’t know if you picked up on, but Walt just mentioned that we actually have some excess cash of about 20% to 25%. So there is money out there for these high-return projects that we either or potentially working on or even not identified at this point. So as far as the specifics go, I’ll kind of turn it over to Walt and Sheridan.

Sunil Sibal:

Thank you.

Michael Blum:

Thanks. Good morning, everyone. So question on Saguaro, if you FID Saguaro in mid-’24, first of all, would that change the ‘24 CapEx number much or would most of that fall into the ‘25 and ‘26? And would that change your expectation that ‘25 CapEx would come down?

Walt Hulse:

Yes, Michael, given the timing, there’s not – if it gets FID midyear, the capital associated with that would not be a material change to 2024. And in 2025 and beyond, I don’t think you’ll see anything that would change my comment before about seeing a reduction over the 2024 level of CapEx as we go forward. Projects takes a couple of years to construct and we’ll fit right in within our capital program.

Sheridan Swords:

Well, Michael, as we think about the Elk Creek expansion, we’ve always said that we’re not going to run out of capacity coming out of the Bakken. And that’s why we want to make sure this pipeline comes up in the first quarter of 2025. So we are expecting volume increases and we’ll need that as we move into 2025. And then there is a lot of things affected on the ramp up. One is how much incentivized ethane we have coming out of there. And if we – and the other one is the continuing growth in the basin as we’ve seen gas to oil ratios continue to grow and drilling activity that we’re seeing right now is conducive to increase overall volumes in the basin. So I think we will see quite a bit of growth as we move into 2025 on this pipeline with those two backdrops.

Operator:

The next question comes from Vrathan Reddy with JPMorgan. Please go ahead.

Sheridan Swords:

Yes. This is Sheridan. Absolutely with more efficiency and then growing 3-mile laterals, so, each well is going to have more production on that. So we are going to see a drop off from our previous cadence on capital that we need to spend in the area to maintain volume. And also remember that in the Bakken, we are guiding a little bit over 1.6 Bcf of throughput, and we have 1.9 Bcf of processing capacity up there. So we have a lot of working leverage to grow in that area. So we will see our capital come down.

Chuck Kelley:

Well, Vrathan, this is Chuck. As far as Northern Border goes, the volumes that we see coming down there today, I don’t think will be appreciably impacted but the Canadian volumes diverted to LNG Canada. There’s a stronghold of about 400 million a day that’s held by long-term producers that will continue to flow down Northern Border. So the pipe will remain full headed toward Ventura in Chicago. And there’s been some relief in our G&P business, working a deal with WBI to move some guests down to Cheyenne Hub and that’s been a nice relief and you’ve probably seen some information about Bison Express which should be coming on in Q2 of 2026 that will offer upwards of another, call it, 400 million a day of relief. So I think the pipe is positioned well for the next couple of years.

Operator:

The next question comes from Spiro Dounis with Citi. Please go ahead.

Sheridan Swords:

Well, I’ll take the first part of that. As we look at each one of those projects, and we think about the ramp-up, MB-6 is going to come up full. We will – because we’re having third-party frac capacity today. So it’s going to be at a very high operating rate. So it’s going to be a very nice multiple we have on that. As we’ve said with the West Texas expansion that we are contracting and continue to contract more volume on that to have an acceptable return with a significant amount of upside going forward. So we’re continuing to drive that projects multiple down as we grow on that. The Elk Creek expansion is probably going to be the lowest one on that as we don’t need a whole lot of volume to be able to have a very low multiple. And if we would get to the point that we are at a high utilization rate, that multiple will be well below 1.

Sheridan Swords:

Yes. I think it’s going to be all that kind of stuff. It’s going to be small – relatively small capital. There’s going to be some connections here, some tanks here, depending all up and down our system. So it – some of that will come before ‘26. But as we continue to look forward to that, we’ll be achieving most of it as we head into the ‘26 timeframe.

Operator:

The next question comes from Jean Ann Salisbury with Bernstein. Please go ahead.

Chuck Kelley:

Jean, this is Chuck. I stand by what I have said. I really think the 400 million a day will continue to come down northern border from the legacy Canadian producers. So, the growth coming out of the Bakken will be absorbed through Bison Express and the WBI expansion.

Walt Hulse:

Yes. And while we think that there is plenty of takeaway, do remember that we always have the lever if we need to, that we can extract more ethane and put it on the NGL pipe to create capacity for natural gas.

Sheridan Swords:

Potentially, I think when we get out in 2025, we will see a little bit more of ethane export capability coming online. A lot really depends on how hard the pet chems are running on utilization is a big impact on. And then as we think about ethane rejection and recovery across our footprint, a lot depends on what the natural gas price in that area is. We feel that we have a very good opportunity to continue to bring incentivized ethane out of the Bakken just from our fully integrated NGL system and G&P system as well. Mid-Continent maybe where we see a little bit of swing, could be a little bit more swing in ethane recovery, but those were at much lower rates than we see coming out of the Bakken. But I think the big thing is going to be is how hard the pet chems are, the utilization rate. And we are seeing as we move into 2024, they are operating at pretty high levels.

Operator:

The next question comes from Keith Stanley with Wolfe Research. Please go ahead.

Chuck Kelley:

Keith, this is Chuck. Yes, as you state, MPL received back in 2019 for the first two trains, the OE export approval. And they have adequate time to go ahead and start this project post-FID where that approval is for both FTA and non-FTA countries. So, I feel pretty good, obviously, about trains one and two, this pause that we are seeing right now impacts their second requested approval, which would be for train three. And as you know, we don’t know exactly how this is going to play out the balance of the year. So, trains one and two post-FID, we feel good about those volumes as we sit here today.

Sheridan Swords:

This is Sheridan. On the LPG exports, I think we are the same spotter what we can share publicly, where we have been for a period of time as you are right, we continue to look at all alternatives that we have. We have a greenfield site. Trying to understand if there is some synergies there from a physical standpoint from the Magellan assets, if we could put something on their sites. So, we continue to do that. But right now, as I have said, we see the LPG export as we think something that could enhance our integration, but it’s not something we absolutely need as we continue to be able to move our barrels through the market today that has the export capabilities at other facilities.

Operator:

Was there a follow-up to that Mr. Stanley?

Operator:

Thank you. The next question comes from Theresa Chen with Barclays. Please go ahead.

Sheridan Swords:

What I would say is, right now, we are not going to comment specifically on refined products, movements on any specific pipeline. What I can tell is NGL pipelines have moved refined products here in the fourth quarter and the first quarter. We do see with that movement in the two pricing mechanisms between the Gulf and the group. We have seen opportunity for longer haul tariffs on our refined products system.

Sheridan Swords:

Yes. There could be some potential as we look at for the natural gasoline component of the barrel, some blending into the unleaded pool that we have looked at. As in terms of isobutane specifically going into alkylate, we have been servicing those alkylate units for quite a long time in the legacy NGL business. And typically, as you know, alkylate is a very high priced and usually, they run those pretty strong. The big difference in those alkylate unit is whether or not they are going to run some refinery grade propylene through that unit or are they going to stay or how their RGBs, refiner grade butane runs through that as well. So, if we see more propylene run through an alkylate unit, we will see a little bit more isobutane being used. But typically, they run pretty steady.

Operator:

The next question comes from Tristan Richardson with Scotiabank. Please go ahead.

Sheridan Swords:

Well, right now, we – it is an option. We haven’t decided to exercise that option. We continue to see good on the NGL side. So, there is a good possibility we want to keep it in NGL service to continue to be able to service our downstream assets in the Mont Belvieu area. If we would decide to shift it to some other product, the big thing is going to have to be determined on which way we run it. Obviously, if we want to run it from Mont Belvieu out to West Texas, it will take us a little bit more time because we will have to do a little bit of work on header systems on that side. If we want another product moving from West Texas in to Mont Belvieu, into the Houston area, it would be quicker because the pumps are already set up going that direction. But as of this moment right now, we are probably leaning more towards the natural gas liquids side of it or the raw feed side of it as we continue to see good growth coming out of the Permian.

Walt Hulse:

Well, clearly, with what we have identified today from a CapEx standpoint, as I have said before, that we would expect that capital return to ramp throughout that period. I think that we will be producing a meaningful amount of free cash flow. Obviously, it will increase when our CapEx number goes down. So, we will still stay in that 75% to 85% availability after CapEx, it’s just going to be a bigger number. So, it will give us more opportunity for shareholder return.

Tristan Richardson:

Peirce, appreciate it. Thank you all very much.

Neal Dingmann:

Good morning. Thanks for the time. My first question is on NGL specifically, just wondering where are you all seeing notable demand pure NGL from the Permian NGL service. Is it mostly in key Midland or Delaware areas? I am just wondering if there are specific areas that we should be looking at there? And then are you all taking market share from Permian contracts rolling off, other pipes or this is more basic expansion?

Neal Dingmann:

Yes, that makes sense. Okay. And then just a quick follow-up on, like that Slide 10 that shows the synergy opportunities. I am just wondering on the batching upside that you laid out here on this slide, just wondered timing-wise, how quickly, I am just wondering are you thinking, and are there key areas that you would anticipate seeing the majority of that batching upside?

Neal Dingmann:

Thank you for the upside.

Craig Shere:

Good morning Thanks for taking the question. On CapEx opportunities, could you opine on the possibility of meeting another frac by 2026? And does the MMP acquisition increase prospects for accretively rebuilding and/or repurposing legacy Medford frac site?

Craig Shere:

Great. And last question, on synergies, it sounds like you expect almost the full $100 million or so in G&A benefits in 2024 which would suggest that you might be being conservative on the commercial side. Is that a fair assessment?

Craig Shere:

Okay. Thank you.

Zack Van Everen:

Hey guys. Thanks for squeezing me in. Just going back up to the Rockies growth, you noted 9% year-over-year in 2024, but it looks like NGL growth is a bit lower than that for the year. Is the majority of that the contract rolls on Overland, or are you expecting just less overall ethane recovery, just trying to kind of put those two numbers together.

Zack Van Everen:

Got it. That makes sense. And then shifting over to the rate adjustments in July, you noted mid-single digits. Just looking at the FERC regulated calculation trending towards 1.5% kind of hints that higher-market based adjustments. Curious if you had any pushback from the customers on that or just how that conversations going overall?

Zack Van Everen:

Okay. Perfect. Thanks guys.

Andrew Ziola:

Alright. Well, perfect timing, everybody. Our quiet period for the first quarter starts when we close our books in April and extends until we release earnings in late April. We will provide details for that conference call at a later date. Thank you all very much and have a great day.

Operator:

Good day and welcome to the ONEOK Third Quarter 2023 Earnings Conference Call and Webcast. [Operator Instructions] Please note, today’s event is being recorded. I would now like to turn the conference over to Andrew Ziola, Vice President, Investor Relations. Please go ahead, sir.

Pierce Norton:

Thanks, Andrew. Good morning, everyone and thank you for joining us. On today’s call is Walt Hulse, the Chief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development; Sheridan Swords, Executive Vice President, Commercial liquids and Natural Gas Gathering and Processing, which includes our commercial responsibility for our NGL business, refined products and crude businesses. Also available to answer your questions are Chuck Kelley, Senior Vice President, Commercial of Natural Gas Pipelines; and Kevin Burdick, who has assumed the newly created position of Executive Vice President, Chief Enterprise Services Officer, with responsibilities for cybersecurity, information technology, enterprise optimization, innovation, and integration activities. This position will be vital as we continue to integrate systems, technologies and workforces following the acquisition of Magellan. Kevin is uniquely qualified for his experience in integration processes, information technology, commercial and corporate operations to lead the company as we continue to identify, prioritize and realize the value of the synergies as one company. We completed the acquisition just over a month ago. And since then, we have been fully focused on integration activities, maintaining the reliable and responsible operations, our customers and stakeholders expect from us. And at the same time, exploring optimization and integrated opportunities by engaging the combined commercial, operational and engineering teams. What has become evident at this point, based on the number of commercial synergies and opportunities is the importance of prioritization, the value of combining our companies, the potential commercial synergies and the opportunities going forward are significant, more to come on this in the coming months. But after September 25 and getting full access to both companies, I can say that the collaboration of our employees is already presenting additional possibilities. ONEOK’s increased scale, scope and diversified operations are already enabling us to create exceptional value for our stakeholders. We have added primarily fee-based earnings and expect a significant free cash flow through the new refined products and crude businesses and expected tax synergies, which combined with ONEOK’s legacy operations, is setting up a strong finish to 2023 and a solid foundation for 2024 performance. Yesterday, we announced third quarter 2023 earnings and increased our full year 2023 financial guidance on a pre-acquisition basis for the second time this year. We also provided new consolidated guidance that includes the impact of the Magellan acquisition. Walt will provide more detail in our guidance a little bit later, which is underscored by our strong volumes across our systems and favorable market conditions continuing to drive confidence in our expectations. We saw double-digit growth in NGL and natural gas processing volumes in the third quarter and continue to see robust producer activity across our operations with North Dakota natural gas production reaching a new all-time high in August. The industry landscape is healthy, and now with a more diversified portfolio of assets, we are even better positioned to make the most of opportunities across our operations. So with that, I will turn the call over to Walt for the financial performance and a guidance update.

Sheridan Swords:

Thank you, Walt. Let’s start with our natural gas liquids segment. Third quarter 2023 NGL volumes increased 11% year-over-year with all regions where ONEOK operates seeing increases compared with the third quarter 2022. Compared with the second quarter of 2023 both Rocky Mountain and Mid-Continent NGL raw feed throughput increased 5%, driven by continued strong production activity in these basins, resulting in higher propane plus volumes and slightly higher ethane recovery levels. Rocky Mountain region volumes averaged more than 400,000 barrels per day in September. The continued growth in volume from the Rocky Mountain region provides momentum into 2024 and further supports why we have started initial long lead time activities for an Elk Creek pipeline expansion. We continue to maintain our ethane recovery assumptions for the remainder of the year, with the Permian in near full recovery, the Mid-Continent in partial recovery and opportunity to incent recovery in the Williston. In the natural gas gathering and processing segment, third quarter processed volumes averaged more than 2.3 billion cubic feet per day, a 12% increase year-over-year. As Pierce mentioned, North Dakota gas volumes have reached record production levels of more than 3.3 billion cubic feet per day in August. Our Rocky Mountain region process volumes averaged more than 1.5 billion cubic feet per day during the third quarter and reached more than 1.6 Bcf per day in September. We’ve connected 450 wells in the region for the – through the first 9 months of the year compared with approximately 245 connections during the same period last year, a more than 80% increase. We have also increased our well connect guidance for 2023 due to the strong pace of completions and now expect to connect 525 to 575 wells compared with our previous guidance of 475 to 525 wells. Currently, there are approximately 37 rigs and approximately 15 completion crews operating in the basin with 20 rigs and approximately half of the completion crews on our dedicated acreage, which remains more than enough activity to grow production. In the Mid-Continent region, third quarter process volumes increased 10% year-over-year and increased 3% compared with the second quarter of 2023. We continue to see producers focus on higher crude producing areas and currently have 3 rigs on our dedicated acreage in the region. We have connected 46 wells in the region through the first 9 months of the year compared with 40 in the same period last year. We expect to be at the high end of our Mid-Continent well connect guidance of 45 to 55 wells in 2023. Moving on to the Refined Products and Crude segment, we only have 6 days of operation from this new segment in the third quarter due to the timing of the acquisition closing, but the segment continues to perform in line with expectations that were already increased earlier this year. Healthy business fundamentals continue to drive consistent performance, and we’re currently seeing strong seasonal butane blending margins. Looking ahead, we see a growing list of opportunities, which will continue to drive growth in this segment through synergies. The more time we spend with the assets and with the legacy Magellan employees, we’re seeing even more opportunities. In the Natural Gas Pipelines segment, strong year-to-date results continue to benefit from demand from natural gas storage and transportation services. And we saw increased demand for interruptible services during the third quarter as extreme heat in Texas drove increased electric generation demand and pricing. We’re seeing opportunities for additional expansion in Oklahoma and Texas, with additional storage expansion in Oklahoma and Texas and demand for long-term storage capacity remaining strong. We continue to work toward FID in the Saguaro Connector pipeline and expect to receive the presidential permit before the end of the fourth quarter. There has been significant interest from producers in the Permian Basin relative to shipping gas west to the potential LNG export facility and reported support from multi-large, well-known customers anchoring the export project. Pierce, this concludes my remarks.

Operator:

Thank you. [Operator Instructions] Today’s first question comes from Brian Reynolds with UBS. Please go ahead.

Pierce Norton:

So I’ll start off and then I’m going to kick it over to Kevin on this. I am going to kind of start with part of your question is kind of what have you seen immediately with some of the kind of the smaller things. As you know, after closing, we do have immediate synergies that have been realized basically from day 1, which are board costs, credit facility renewals, cyber insurance, audit fees and then the executive organizational design that was put in place. So all of those kind of things added up to some immediate savings that will be annualized primarily in next year. I’m going to turn it over to Kevin to kind of talk a little bit more about the process, both on the small things and the large things.

Brian Reynolds:

Great. Thanks. Appreciate all that. Maybe to pivot just towards the forward growth CapEx outlook relative to the initial S-4, it seems like ONEOK has pulled forward some CapEx related to West Texas LPG and Elk Creek expansion. And it seems like Saguaro is trending towards more of a JV type relationship, which could defer capital further. So perhaps could you just update us on kind of a forward CapEx outlook maybe for ‘24 and beyond? Just given some of these recent trends? And does it imply that ONEOK could be trading closer to a 10% free cash flow yield if CapEx trends lower? Thanks.

Brian Reynolds:

Great. Fair enough. I will leave it there. Have a great rest of your morning.

Jeremy Tonet:

Hi, good morning.

Jeremy Tonet:

Just maybe one to pick up on the last question a little bit and fully appreciate not giving ‘24 guidance today, but just trying to get a state of affairs as it stands right now. And I think I wanted to be kind of clear, I guess, on the guidance. And if I’m looking at this the right way, if what’s implied for remainder of the year for fourth quarter, just over $1.4 billion, but then on a normalized basis, you back out most of that $50 million inventory adjustment and then there is a $40 million or so of transaction costs. So it seems like the run rate for the business might be close to $1.5 billion looking at 4Q. Now granted there is seasonality that can impact that at different points throughout the year, but then you also have $200 million of synergies from Magellan that should be realized and you have an increasing GOR and there is other projects set to come on over time in ‘24. I’m just wondering, moving pieces wise, is that encapsulate what we should be thinking about? Is that a good base to work off of or any other color on these pieces would be helpful?

Jeremy Tonet:

Got it. That’s very helpful. And I guess I wouldn’t be a Wall Street analyst, if I wasn’t asking now that the ink is dry on the Magellan agreement, anything you can share on what you’re working on now going forward?

Jeremy Tonet:

Got it. That’s helpful. I will leave it there, thanks.

Michael Blum:

Thanks. Good morning, everyone. I wanted to ask on the West Texas NGL pipeline expansion. In the slide, you mentioned optionality to use the legacy system for NGLs refined products or crude. I’m wondering if you could just expand on that? Is there any way to get a sense of how you think that will kind of split over time?

Michael Blum:

Okay. Got it. Thanks for that. And then just one question on the Bakken. So it seems like the Bison Express pipeline project is moving ahead. So I wanted to just get your thoughts on that project. Does this reduce ethane recoveries volumes for you? Or ultimately should we think of this as sort of a tailwind because ultimately, it opens up the potential for more natural gas production in the basin, which obviously would lead to more associated NGL production?

Michael Blum:

Great. Thank you.

Spiro Dounis:

Thanks, operator. First question just maybe on the export opportunity. I don’t think that was a synergy necessarily when you announced the deal, but something you may’ve been better positioned to do post Magellan. Just curious where that stands now and then expanding into exports is kind of high on the priority list of things to do post close?

Sheridan Swords:

The only thing I would add to that, Pierce, is that with the addition of the Magellan employees, we have much more confidence in both our engineering and operation capability since that is what they bring to the table since they are already operating marine docs and built marine docks.

Sheridan Swords:

What I – this is Sheridan again. What I would say on competition coming in the basin is what we’ve said for many times is that on the G&P side, we have 60% of the market share, and that feeds our NGL pipeline. So we very – feel very secure about that volume. And then on the third-party NGL customers, we have long-term contracts with them, and that also gives us a surety that we will be able to maintain our volume coming out of the Bakken and be able to capture the growth going forward.

Operator:

Thank you. And our next question today comes from Tristan Richardson with Scotiabank. Please go ahead.

Walt Hulse:

Yes, well, Tristan, as I just mentioned, our debt metrics are coming in line even quicker than we had expected. We continue – we think that direction will continue. And that’s going to give us significantly greater flexibility as we move forward to think about capital allocation. It’s going to give us plenty of capital to take advantage of high-return projects as they become available and think about ways of returning value to shareholders. And we’re going to lay that out as we get into ‘24 as we see forward where our debt metrics are headed and we will give you more clarity as we get into February.

Sheridan Swords:

Tristan, that’s a good question. And we’ve had that talk to our producers about that as well. And they don’t know where the top end of it is. What we do know is as wells continue to age, the GOR continues to grow up – grow. Now we do see some up and down in the GOR overall for the basin because as new rigs come on, depending on where they come on, they may have a starting point of a lower or higher GOR. So overall, it makes it move around. But every well up there as it continues to decline, the GORs continue to rise. And so that gives us a lot of confidence that even in a flat crude environment, which crude is growing right now, but in a flat crude environment, we are still going to see some pretty good growth in the gas volume in the basin.

Operator:

Thank you. And our next question today comes from Jean Ann Salisbury with Bernstein. Please go ahead.

Sheridan Swords:

I would say that we have long-term contracts. That’s the people that we have contracted with both now and for the LPG expansion or the NGL expansion are long-term contracts. So we feel comfortable that we have the volume behind to be – to have a very favorable return on that project and with a lot of upside as we continue to grow. We think it’s a very cost-effective way to do it, that we can be able to compete going forward even as new pipelines come online.

Sheridan Swords:

On the liquids pipelines, on the NGL pipeline, a lot of it is more driven by individual contracts as we do as not as much on the tariff itself. And then there is a larger portion of that on our new refined product system that contain that – but about 70% of our tariffs on the refined product system are at market rate that we can move as we want to. And so 30% would be more on a FERC tariff rate.

Operator:

Thank you. And our next question today comes from Harry Mateer with Barclays. Please go ahead.

Walt Hulse:

Well, Harry, we’re pretty positive on ‘24 and where things are headed. So I think that we expect to continue to make progress on our leverage metrics as we go throughout 2024. We have said aspirationally all along, that 3.5% is a good spot to be. We don’t care if we go below it a little bit. That’s fine. If we have got significant earnings and it drives our debt-to-EBITDA below 3.5%, that’s a good problem to have. So, we are very pleased with the trajectory of that credit metric and have no reason to think it’s going to change any direction.

Walt Hulse:

Well, I am not going to say we will or we won’t be in the bond market, but I would just say that the last several maturities that we have had, we have called for cash. We are generating a lot of cash. So, I think we have got the flexibility to manage our debt portfolio in a very comfortable manner. But we are going to keep our flexibility. If it makes sense for us to go to the credit markets for a reason, we may or may not do that. But you can see what we have done in the last several. And given the size, we are probably going to maintain that flexibility.

Operator:

Thank you. And our next question today comes from Neal Dingmann with Truist Securities. Please go ahead.

Kevin Burdick:

I mean just in general, as we look at the synergies, obviously, they are going to – there is going to be a variety of scenarios that play out. Some will get very quickly, potentially by the end of the year. There may be others that are going to take some capital and some effort to put things in the pipeline in the ground or other activities like that, that may span out of ways. So, it will be a blend. But I think again, the focus here is that our confidence level in achieving these things continues to grow as we get more information.

Pierce Norton:

Well, I said – this is Pierce. What I am going to tell you is that to kind of tag it on to what Kevin is saying is that we are confident that these opportunities are there. It’s just a matter of the timing of when they come in, and we will let you know that as we give our guidance from year-to-year.

Sheridan Swords:

Neal, this is Sheridan. Yes, we still are seeing good activity in the Bakken. We have increased our well count activity, and that’s to show you what we are seeing. And we think that’s going to continue or know that’s going to continue into 2024 in the Bakken. So, we are very excited about that. And that’s why we continue moving on long lead time items with the Elk Creek expansion. And then the Mid-Continent, as we said multiple times, has really been surprising us to the upside that more producer activity out there, especially with oil-driven rigs that is producing high GPM or high liquid content gas, that’s really – not only producing more gas in the region, but also more liquids for the NGL pipeline. So, we continue to see growth being very – we are very optimistic about growth going through the fourth quarter and into 2024.

Operator:

Thank you. And our next question today comes from Theresa Chen with Barclays. Please go ahead.

Sheridan Swords:

Theresa, yes, we do think there is a little bit this quarter. As you said it, a lot of it has been locked down or been hedged, but we do have some above that, and we are seeing wider spreads at this time, so availability is there, and also with our position, legacy normal butane position. There is opportunity there. We will have the butane available, and we can work a little bit on logistics cost. We think most of that’s really going to come as we come into next year where we will see a much bigger opportunity for synergies in the butane blending in the 2024 timeframe.

Operator:

Thank you. And our next question today comes from Keith Stanley at Wolfe Research. Please go ahead.

Sheridan Swords:

Keith, we continue to look at that, and we have looked at a lot of different opportunities out there. What I can tell you is just by us expanding, we started off at about 140,000 barrels a day, now we are going up to 700,000 barrels a day. It has not been an impediment for us to be able to contract NGLs on that pipeline. But we will continue to look at as opportunities come if we need to get into the G&P space. And if it makes sense, we will get into it and do that. But so far, we have been able to contract and expand that pipeline without having a G&P presence. And a lot of that is, as you think about it, we have a very integrated value chain in touch. A lot of the producers out there in many different areas, so if we look holistically across our system, we can create and offer a very attractive program to them to incentivize barrels coming on to our West Texas system.

Keith Stanley:

Got it. Thanks for that. Second question on SWRO [ph], and sorry if I missed this, but – can you say, are you in discussions or looking at working with potential partners on the project, or do you think it’s more likely you would move forward on that by yourself?

Keith Stanley:

Okay. Thank you.

Sunil Sibal:

Yes. Hi. Good morning everybody and thanks for taking my questions. So, my first question was related to the West Texas LPG and I apologize if I missed this, could you indicate what is that system running at right now? It seems like, you had a little bit of a step down in volumes.

Sunil Sibal:

Yes, ballpark.

Sunil Sibal:

Okay. And thanks for that. And then my second question was a little bit more broader. We have seen a number of E&P deals announced over the course of last few months. And I was curious if you had any dialogues with your E&P customers with regard to that, and how is that impacting your dialogue with the producer customers?

Sunil Sibal:

Okay. Thanks. Thanks Pierce.

Neel Mitra:

Hi. Good morning. Thanks for taking my questions. It seems like everything is going well, you are going to be below 4x leverage easily for 2024 and the $6 billion in guidance seems pretty conservative. How are you looking at shareholder returns right now? Is a repurchase program in 2024 on the table, just as we look for how to return cash to shareholders after this merger and when we can think about how we are going to do that?

Neel Mitra:

Okay. Great. And then second question on building an LPG terminal on the Gulf Coast. Some of your peers have talked about how they initially priced at greenfield and now they will price everything at brownfield to try to combat new entrants. Does this make LPG exports or a new terminal kind of lower on the priority list than the batching, bundling, etcetera, when you consider the barriers to entry just with pricing for existing players that are in the space right now?

Neel Mitra:

Got it. I appreciate the commentary. Thank you.

Craig Shere:

Congratulations on the closing and quarter, and thanks for taking the question. Just one for me, and you kind of talked around this a little bit or kind of responded to some Q&A on it. But Pierce, you mentioned prioritizing incremental commercial opportunities identified post close at the start of this call. And I am a little unclear, given all the commentary, if this is mostly about chopping wood and management bandwidth or despite better than expected deleveraging, are you starting to see more accretive capital deployment opportunities than you are prepared to pursue all at once?

Craig Shere:

Fair enough. Thank you.

Andrew Ziola:

Alright. Thank you everybody. 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 will provide details for that conference call at a later date. Thank you for joining us and have a good day.

Operator:

Good morning, everyone, and welcome to the ONEOK Second Quarter 2023 Earnings Conference Call and Webcast. [Operator Instructions]. I would now like to turn the conference over to Andrew Ziola, Vice President of Investor Relations. Please go ahead.

Pierce Norton:

Thanks, Andrew. Good morning, everyone, and thank you for joining us. On today's call is Walt Hulse, Chief Financial Officer; and Executive Vice President, Investor Relations and Corporate Development; and Kevin Burdick, the 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, Senior Vice President, Natural Gas Pipelines. Yesterday, we announced second quarter 2023 earnings and increased our full year 2023 financial guidance. Strength in volumes across our operations, particularly in the Rocky Mountain region and Permian Basin, resulted in higher second quarter results and positive momentum entering the second half of 2023. We continue working toward a successful closing of our pending merger transaction with Magellan while remaining focused on the growth of our legacy assets. Initial activities have begun on 2 NGL pipeline expansion projects. The growth we are seeing across our existing operations is driving the need for these economically attractive projects. Walt and Kevin will talk more about the early work that we are doing on the Elk Creek and West Texas natural gas liquids toplines. Regarding our pending acquisition of Magellan Midstream. We've recently accomplished 2 critical milestones toward completing the transaction, including the expiration of the HSR waiting period in June and the filing of the definitive proxy materials with the SEC in July. Proxy mailings are already hitting investors' mailboxes. As we look ahead to the shareholder and unitholder votes on September 21, we're confident that the investors of both companies will see the compelling long-term value proposition this transaction brings with immediate financial benefits and incremental growth through the combination of these 2 companies. Today, we will walk you through both the macro and micro takeaways of our synergy assumptions. I will cover the macro and Kevin will go into more detail with the macro explanations. On Slide 6 in our earnings presentation, which was provided yesterday with our news release, you will see a summary of how we've organized the synergy opportunities we've identified to date and have targeted to realize as a combined company. You can see we have slided these commercial opportunities into 4 categories and have provided a breakdown for both the assumed scenario in our proxy and for the incremental potential near-term commercial opportunities. So now I'd like to cover the macro takeaways from Page 6 previously referenced. First, combined, these companies will have opportunities that were not possible as stand-alone companies. Second, batching and blending are done by both companies today. Therefore, these operational techniques are well understood by both companies. They are not new. But the difference is with these assets under one company's direction, batching and blending value can be realized on a larger scale. Third, with the exception of bundling, the 3 remaining commercial categories are within 100% of our control. This means that we make the decision to pursue opportunities if they make commercial and economical sense instead of relying on factors outside of our control. Fourth, as we integrate the 2 employee bases post close, we can focus on widespread collaboration and believe that we will find even more opportunities not identified to date. And finally, there is significant potential value in the near term, the next 1 to 4 years, above our assumed case in the proxy. ONEOK has proven our commercial creativity over the course of our company's transformative history, and together with Magellan's team, we believe our companies have many opportunities to continue improving the services that we offer to our customers and returning value to our investors. With that, I'll turn the call over to Walt Hulse, for the discussion of our recent financial performance and guidance increase.

Kevin Burdick:

Thanks, Walt. Let's start with our Natural Gas Liquids segment. Second quarter 2023 NGL volumes increased 11% year-over-year and compared with the first quarter 2023. Higher volumes were driven by increased producer activity, particularly in the Rocky Mountain region and Permian Basin. Both regions saw double-digit volume increases year-over-year and compared with the first quarter 2023. Permian Basin volumes saw the largest increase, up 26% year-over-year, driven by continued growth from existing plants and volume from a new plant connection in the first quarter of 2023. Volumes in the Rocky Mountain region increased 17% compared with the first quarter of 2023 and 14% compared with the same period last year driven by increased propane plus volume and slightly higher incentivized ethane. Mid-Continent region volumes increased 8% compared with the first quarter of 2023, partially driven by increased ethane recovery. While we've seen ethane prices decrease recently from July highs, they remain at a level driving recovery in most basins. We think the recent volatility in ethane pricing is the market responding to some short-term dynamics along with the general tightening in the overall supply and demand balance. Given these market conditions, we remain confident in our ethane recovery assumptions included in our updated guidance. The Permian in near full recovery, the Mid-Continent in partial recovery and opportunities to incent recovery in the Williston. As Walt mentioned, we've begun initial work, including purchasing long lead time components for 2 NGL pipeline expansion projects. Activities are underway to complete the looping of West Texas NGL pipeline, which will more than double ONEOK's NGL capacity out of the Permian Basin. The full loop is expected to be in service in the first quarter of 2025, which aligns with our customers' needs. We also are taking steps towards expanding the Elk Creek pipeline to 400,000 barrels per day to provide capacity for growing volumes in the Williston. In the natural gas gathering and processing segment, second quarter processed volumes averaged nearly 2.2 billion cubic feet per day, a 16% increase year-over-year. In the Rocky Mountain region, processed volumes averaged nearly 1.5 billion cubic feet per day during the second quarter and have averaged more than 1.5 bcf per day in the month of July. We've connected more than 280 wells in the region through the first half of the year compared with approximately 160 connections in the first half of 2022, a 75% increase. As we sit today, we're on pace to reach the high end of our 475 to 525 well-connect guidance range for the year. Currently, there are approximately 35 rigs and 20 completion crews operating in the basin with 19 rigs and approximately half of the completion crews on our dedicated acreage which remains more than enough activity to grow production on our acreage. In the Mid-Continent region, second quarter processed volumes increased 12% year-over-year and decreased slightly compared with the first quarter of 2023, primarily due to the timing of new pads coming online. We've seen some recent decreases in STACK and SCOOP activity in the past few months but continue to see increased activity in Western Oklahoma as producers are focusing on higher crude producing areas. We currently have 9 rigs on our dedicated acreage in the Mid-Continent and have connected 23 wells in the region through the first half of the year. In the natural gas pipeline segment, strong year-to-date results continue to benefit from demand for natural gas storage and transportation services, and we now expect the segment to exceed the high end of its original earnings guidance range. We recently completed an expansion of our natural gas storage capabilities in Oklahoma, allowing us to utilize and subscribe an additional 4 billion cubic feet of our existing capacity. We have subscribed 100% of this incremental capacity through 2027 and 90% through 2029. We continue to evaluate the Saguaro connector pipeline, a potential intrastate pipeline project that would provide natural gas transportation to the U.S. and Mexico border for ultimate delivery to an export facility on the West Coast of Mexico. There continues to be positive developments related to the potential LNG export project with support from multiple large, well-known customers anchoring the project. We expect to make a final investment decision on the ONEOK pipeline later this year. Now I want to end where Pierce left off with a micro look at the Magellan transaction synergies. I will discuss how we define each category, an example of the opportunity, the sensitivities and comments on the overall risk weighting. The dollar ranges between our assumed case and the near-term potential are shown on Page 6 of our investor presentation for all 4 categories. Liquids pipelines provide opportunities to move natural gas liquids and refined products through the same product pipelines. Both companies refer to this as batching. This operational technique utilizes available capacity and combined connectivity to ship a refined product or natural gas liquid to a demand center to capture a higher value. An annualized average of 100,000 barrels per day in any combination of refined products or NGLs at $0.07 per gallon would result in more than $100 million annually. The ability to mix products to obtain a higher value is called blending. The combined assets will increase unleaded butane blending as well as other incremental blending opportunities, increasing an additional 25,000 barrels per day annually at a $0.20 per gallon uplift on any given slate of products or NGLs would result in approximately $75 million annually. As volumes grow or contracts expire, a wider variety of services can be combined or bundled to offer greater value to customers. This focuses on optimizing system utilization and connectivity to and from key customers and market centers. This is the one category where time and decisions, primarily by customers, will jointly be needed to realize this synergy. Picking up an incremental 25,000 barrels per day at $0.10 per gallon would provide approximately $40 million a year. Additional opportunities that can be realized within the 1- to 4-year time frame include incremental refined product, NGL, and crude oil storage and optimization activities. We also see value and opportunities to leverage Magellan's proven marine export expertise. We have consistently said that acquisitions of this size often result in a 25% reduction in G&A cost, which, in this case, would be $200 million. However, we have assumed only $100 million in both the assumed case and the near-term potential case. It's also important to point out when the transaction was announced, we significantly risk-weighted our financial assumptions to come up with our total assumed $200 million of synergies. This should highlight the level of conservatism we've applied to our expectations and also the potential upside to our assumptions, which we think could drive synergies to more than $400 million. As we've said previously, we have a high level of confidence in achieving the assumed $200 million of near-term synergies. For obvious commercial reasons, we're not going to provide specific project level details at this time. However, we have provided realistic potential outcomes by categories. We believe our ability to batch and blend products on our combined pipeline systems as well as bundled services to increase value for customers will provide significant synergy opportunities over the next 1 to 4 years. Pierce, that concludes my remarks.

Operator:

[Operator Instructions]. Today's first question comes from Brian Reynolds with UBS.

Pierce Norton:

So this is Pierce. Brian. I'll start out with some comments, and I'll let Kevin fill in or share in either one. So the $800 million is a list of opportunities that we have that's fairly lengthy as far as what the potential could be based on certain volume assumptions, pricing assumptions, and time. And so you come up with your list first, and then you have to go back and risk weight those as to what you think can realistically be done. I think in any of these transactions, you want to come up with the most comprehensive list possible realizing that you may not get them all. So we're very comfortable in that range of $200 million to $400 million. And so -- but we wanted to add the color to kind of show how we risk weighted both into that assumption.

Kevin Burdick:

Brian, it's Kevin. No, I mean we've kind of provided as much as we're going to provide at this time. Again, just for competitive reasons, we're not going to -- we don't -- we prefer not to get into the details at this time of some of that. A lot of these will happen with not a lot of capital. Some may require a little bit, but we'll work those details as once we get closed and get into it.

Brian Reynolds:

Fair enough. And if I may just -- I know it's a little bit too early to discuss what the final company will look like post-merger but kind of just curious if you could just talk about leverage for a larger integrated company. We've seen NGL peers take leverage to 3x. And we've seen some recent spin co announcements talk about 5x as being the right number. So just kind of curious as a combined entity, what do you think the right leverage target is for ONEOK and Magellan?

Operator:

The next question comes from Jeremy Tonet with JPMorgan.

Kevin Burdick:

Jeremy, it's Kevin. I think it's shaping up very well. The activity levels we're seeing across our footprint really in all 3 of the major areas. And even a little activity in the Powder, but primarily the Bakken and the Permian announcing or talking about these expansion projects that we're pushing forward to me signals that volume's coming and the activity levels we're seeing right now in the Williston and the Permian would absolutely dictate that we would be continuing to grow as we move through '24.

Jeremy Tonet:

Got it. Maybe just one more cut at this. Is there any way, I guess, to provide color on what inputs were for -- driven into the 2024 numbers, such as Bakken rig count or other? And how they trend now versus what you saw at that point in time?

Jeremy Tonet:

Got it. Just real quick last one, if I could. If you could provide updated thoughts on the West Texas LPG loop and Elk Creek, what type of project economics you see for those investments?

Operator:

The next question comes from Theresa Chen with Barclays.

Sheridan Swords:

I think we, this is Sheridan again. I'll give you 1 example of what we can do it as a batching opportunity is obviously with our Sterling pipeline that runs in between the Gulf Coast and the Mid-Continent region. We can put refined products on that to move refined products in between those 2 locations on the safe pipeline as we are moving NGLs on that pipeline as well. So that's an example of an area where we could be moving back and forth between two areas on refined products on the NGL pipeline. That's an example of batching.

Sheridan Swords:

The reason we use $0.07 illustrated estimates, that's kind of what we see the overall tariff in between those 2 areas tend to be from more on the refined products pipeline as we see that, then obviously, there could be upside to that as we go forward, depending on where the markets are. But that's -- we wanted to use a number that was out there in the market, and that's what we see today.

Sheridan Swords:

I think we see a lot of opportunities in both areas. We're trying to give you an idea of what the impact could be and give you more of a notionally where we're thinking about going on that. It could be both. We could be -- we think that there's opportunity for increased margin. We also think there's an opportunity for increased volume. But we're trying to give you an idea of what the impact could be and a little bit of sensitivities around that. That's how we came up with the numbers that we gave you.

Michael Blum:

I want to go back to the proxy again for a minute specifically on the CapEx in the proxy for 2023, it's higher than your revised CapEx guidance here this morning. So I'm wondering if you could just explain the variance there? And then does that imply that '23 CapEx could go higher if you FID more projects for the balance of the year?

Michael Blum:

Okay. Perfect. And then I just wanted to ask on the Elk Creek expansion, I'm assuming that this will be brought on in phases. So is that correct? And anything you can provide in terms of a timeline for when you'll be adding capacity? And then what is the cost of the project?

Operator:

The next question comes from Spiro Dounis with Citi.

Kevin Burdick:

I mean, this is Kevin. Again, we're not going to start guiding to '24 yet, but just notionally, you think about the projects, we've got our -- at the activity levels we're seeing, it'd be relatively consistent from just kind of that routine stuff. So to the extent we don't announce any other larger projects than it would be in the ballpark. But again, like Walt said, we're constantly looking at projects. We're evaluating projects and some pop and get to the point where we execute and others don't. So it's kind of hard to say. But we don't -- there's nothing we're seeing other than Saguaro. It's more pipeline expansion type stuff.

Kevin Burdick:

Our focus right now on Saguaro is -- I mean, like we said in the remarks, there have been some positive developments, that's great. But our focus is on continuing to drive out and ensure we get the presidential permit and the timelines we need and continuing to refine our estimates, and we're focused on that -- the U.S. side of that pipeline.

Tristan Richardson:

Kevin, you talked a little bit about the volatility we saw in June and July around ethane. But can you talk about maybe the dynamic you're seeing in the north obviously, with a tighter market at Belvieu with relief on the way and then obviously, weather's impact there. Were we able to see some incentivized ethane come in, into June? And then just curious maybe what you're seeing in the third quarter?

Sheridan Swords:

One thing I'd add with that is that with this -- we had a big run-up in ethane prices, and it came off and overall is still higher than it was in the first part of June, which has allowed the Mid-Continent for later part of June, July and into August to be in full ethane recovery.

Walter Hulse:

Well, I think that I would -- as you look forward, kind of think about it this way, that as Kevin mentioned, most of what we're looking at is build-outs from our existing system whether it's expansions or add-ons to that. So at the moment, we don't have any significant sized project that we have looming out there other than we've obviously talked about the potential of the Saguaro pipeline. And the long lead times. In this environment, you always have to be on that game. And so we are looking at that as it relates to all of our projects and how we can be there to meet the needs of our customers going forward. So that's just a reality in this day and age.

Jean Salisbury:

Kevin, can you give a little bit more detail on why the gas pipeline segment is doing so much better than guidance? It seems like a lot of it is from renegotiating storage up to higher rates. So if you can give any kind of direction on how much of your storage capacity has been renegotiated up to the current rates already? And how much might be yet to come, that would be helpful as well.

Jean Salisbury:

Great. And one more for you, if I can. It seems like Bakken volumes are outpacing your expectations a bit. If you can just kind of say whether that's primarily been a function of more oil growth overall, higher GOR than you forecast or more ethane recovery than you forecast or just all 3, that would be helpful.

Operator:

Next question comes from Neil Mehta with Bank of America.

Sheridan Swords:

Neil, this is Sheridan. A lot of that, obviously, the increase in rates is going to be -- we had inflationary factors in there. Depends on the contract mix where -- what contracts coming in there. We've renegotiated contracts. So it's overall, as we move through, we continue to improve those contracts, to go forward. But I think one of the biggest ones is probably more of the inflationary escalators having the biggest impact.

Kevin Burdick:

Neil, this is Kevin. I'll take it, and again, we're not going to get into project-specific details. But I think Sheridan mentioned earlier, it's going to be -- those opportunities are going to be a mix of both. It's going to be volumetric, and it's going to be rate. And to the extent we can find opportunities for the higher rates, great. If it's more volume, that's great, too. So that's kind of how we're thinking about it.

Keith Stanley:

First, just a quick follow-up on the blending synergies, the $70 million to $195 million. Is that predominantly butane blending? Or are there other types of product blending activities you see with the merger? I asked just because Magellan's business today is about $150 million a year on butane blending. So the synergy number is just pretty large.

Keith Stanley:

Got it. And second question, just want to better understand the components of Saguaro. So it seems like Mexico Pacific's made really good progress with the trains being fully commercialized the first 2 anyway. Can you give an update on where you see things for the connecting pipeline in Mexico? I just have not heard as much about that. Is your understanding there's a lot that needs to be done on that to move forward? Or that's progressing well as well and consistent with your timeline?

Operator:

The next question comes from Neal Dingmann with Truist.

Sheridan Swords:

Yes, Neal, this is Sheridan. Yes, there's some -- I think there's some opportunities near term, but it is going to be a little bit lumpy. As we said in the remarks, it's a lot is going to be dependent on when contracts come up and as we continue to see how these 2 assets work together and multiple touch points with the same customer is going to create opportunities. So we're going to see some in the beginning and then as contract roll off, will be lumpy throughout the 4-year time period.

Craig Shere:

You add existing asset and commodity optimization synergies, I just want to dig in a little different manner, more into Brian's question on combined growth project opportunities. I understand you don't want to get into commercially sensitive areas maybe relating to crude transport, exports and all kinds of other things. But would it surprise you to see the combined business perhaps produce $2 billion to $3 billion more aggregate incremental growth project opportunities at your normal historical 4x to 6x build multiple by late decade.

Craig Shere:

Got you. And one other follow-up, maybe a little over the skis on this because you've got to finish the merger, but -- once we get past that, do you intend to break out commercial synergies on an ongoing basis?

Operator:

The next question comes from Sunil Sibal with Seaport Global Securities.

Pierce Norton:

Well, I think the way I'd answer that question is that both companies right now, we're focused on the vote. Magellan is focused on their vote and ONEOK, we're focused on our vote. We believe that the Magellan unitholders and the ONEOK shareholders are going to see the value in this deal, the combined companies. And I think we're scratching the surface there because when we get these 2 companies combined, I think and get our employees collaborating together, I'm very confident in the innovation of both companies is going to turn out to be something that people are going to really be proud that they voted yes for this deal.

Walter Hulse:

Sure. I'm actually glad you asked that question. That is just renewing the ATM plan that we have had in place for better part of 7 or 8 years. We've had -- we have not utilized that within the last 5 years and don't really have any expectation to utilize it going forward. But we do think it's a nice liquidity tool to have in our -- to have available to us, but there is no expectation that we would be using the ATM on a going-forward basis.

Andrew Ziola:

Our quiet period for the third quarter starts when we close our books in October and extends until we release earnings in late October. We'll provide details for that conference call at a later date. Thank you all for joining us, and have a good day.

Operator:

Good day. And welcome to the ONEOK First Quarter 2023 Earnings Conference Call and Webcast. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Andrew Ziola, VP of Investor Relations. Please go ahead.

Pierce Norton:

Thanks, Andrew. Good morning, everyone, and thank you for joining us. On today’s call is Walt Hulse, our Chief Financial Officer and Executive Vice President, Investor Relations and Corporate Development; and Kevin Burdick, the 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 first quarter 2023 earnings and affirmed our full year 2023 financial guidance. Strong first quarter results were supported by continued earnings growth in each of our businesses, with higher Natural Gas Processed and Natural Gas Liquids volumes, providing a solid start to the year. Producer activity continues to drive new volume to our assets and recent conversations with customers point to additional activity through the remainder of the year. Crude prices well above breakeven economics in the Basins where we operate and continued strong demand for U.S. energy support, a constructive outlook for 2023. We provide midstream services to some of the largest, most well-capitalized producers in the U.S., helping contribute to our history of earnings stability and growth despite commodity prices. We continue to evaluate infrastructure and the needs of these customers so that we can provide added capacity or services aligned with their growth. The successful completion of our Demicks Lake III natural gas processing plant and MB-5 fractionator projects provide additional system capacity and resiliency, and are examples of our continued focus on organic growth aligned with our customers’ needs. We remain financially well positioned with significant balance sheet strength and flexibility to support continued growth. Our capital allocation priorities remain consistent, with ONEOK’s unique ability to identify and execute on high return organic growth opportunities setting us apart. With that, I’ll turn the call over to Walt for a discussion of our financial performance.

Kevin Burdick:

Thank you, Walt. Let’s start with our Natural Gas Liquids segment. First quarter 2023 NGL volumes increased both year-over-year and compared with the fourth quarter of 2022, with higher producer activity levels driving increased C3+ or propane plus volumes on our system. Permian Basin volumes saw the largest increase up 17% compared with the first quarter of 2022 and 14% compared with the fourth quarter of 2022. We continue to have success contracting additional volumes in the Basin and connected one new third-party natural gas processing plant during the first quarter. Permian producer activity remains strong and we continue to consider incremental expansions on our West Texas NGL system to accommodate increasing volumes. Volumes in the Rocky Mountain region increased during the first quarter compared with the same period last year and decreased slightly compared with the fourth quarter 2022. The decrease was driven entirely by reduced ethane recovery as our propane plus volumes increased sequentially. We expect volumes to continue to grow in the spring and summer months. In the Mid-Continent region, consistent producer activity in the STACK and SCOOP continues to drive NGL volumes on our system. Raw feed throughput volumes increased compared with the fourth quarter 2022, driven primarily by higher ethane recovery. Regarding the macro ethane environment, we expect domestic petrochemical utilization rates to continue to improve as we move through 2023. With lower sustained natural gas pricing and lower ethane inventory levels driving improved ethane economics and volumes across our system. Through the remainder of the year, we continue to expect that the Permian Basin will stay at high levels of ethane recovery, the Mid-Continent will be in partial recovery and that we will have opportunities for incentivized recovery in the Rocky Mountain region. In April, we completed our 125,000 barrel per day MB-5 fractionator in Mont Belvieu. With MB-5 now fully operational, our system-wide fractionation capacity is nearly 900,000 barrels per day. The added capacity will be used to accommodate volume growth and reduce third-party fractionation needs. We remain on track to complete our MB-6 fractionator in the first quarter of 2025. In the Natural Gas Gathering and Processing segment, first quarter processed volumes averaged more than 2.1 billion cubic feet per day, an 11% increase compared with the first quarter of 2022. In the Rocky Mountain region, processed volumes averaged nearly 1.4 billion cubic feet per day during the first quarter and have recently reached more than 1.5 Bcf per day. We connected nearly 150 wells in the region during the quarter, compared with approximately 90 connections in the first quarter of 2022, a more than 60% increase. Well connections in the region are currently on pace to exceed our guidance midpoint of $500 million for the year. There are currently approximately 40 rigs and 23 completion crews operating in the Basin with 20 rigs and approximately half of the completion crews on our dedicated acreage. We continue to expect additional rigs entering the region as we exit winter. In the Mid-Continent region, first quarter processed volumes averaged more than 750 million cubic feet per day, a 27% increase year-over-year. We connected 11 wells in the region during the first quarter, compared with six in the first quarter 2022 and are on track to be within our guidance of 45 to 55 connections. There are currently more than 50 rigs and 11 completion crews operating in the region, with 10 rigs on our dedicated acreage. Despite weakness in natural gas prices, we continue to see strong activity in the higher crude and NGL rich producing areas of the region, where producers are focusing their drilling. In the Natural Gas Pipeline segment, strong first quarter results continue to benefit from firm transportation services and the demand for natural gas storage. We are on track to complete an expansion of our natural gas storage capabilities in Oklahoma in the second quarter, allowing us to utilize and subscribe an additional 4 billion cubic feet of our existing storage capacity. We have subscribed 100% of this incremental capacity through 2027 and 90% through 2029. We continue to evaluate the Saguaro Connector Pipeline, a potential intrastate pipeline project that would provide natural gas transportation to the U.S. and Mexico border for ultimate delivery to an export facility on the West Coast of Mexico. There continue to be positive developments related to the potential LNG export project and we still expect to make a final investment decision on the ONEOK pipeline in mid-2023. Pierce, that concludes my remarks.

Operator:

Thank you. [Operator Instructions] And the first question will be from Brian Reynolds from UBS. Please go ahead.

Walt Hulse:

So, Brian, as we said in the remarks, we expect that $46 million level to be viewed as kind of a run rate going forward with the potential for us to do better as we bring up MB-5 throughout the balance of the year.

Kevin Burdick:

Yeah, Brian, it’s Kevin. I think we see similar activity levels, if not a little bit stronger. Now we did as -- if you remember in the fourth quarter, we were a little light on our connections and said that just timing had slipped some of those into the first quarter, so that was part. But there -- the activity levels with 20 to 20-plus rigs on our acreage and that looking to be consistent, if not growing moving forward. I don’t see the activity level slowing down. That’s why we think, right now we’re -- with those tailwinds looking that we’d be ahead of our midpoint of the guidance for the well connects.

Operator:

And the next question will be from Jeremy Tonet from JPMorgan. Please go ahead.

Pierce Norton:

Good morning, Jeremy.

Jeremy Tonet:

I just want to dial into the Bakken a little bit more, if I could. That was helpful with the 1.5 Bcf per day volume number that you provided there, but just wondering on the NGL side itself. I think we saw the Bakken NGLs tick down a little bit quarter-over-quarter, but the rates went up a little bit quarter-over-quarter. Just wondering, I guess, where you see that now? How you think about NGL volumes trending in kind of like the ethane extraction economics at this point?

Jeremy Tonet:

Got it. That’s helpful. Thanks. And just wanted to kind of pivot with the insurance proceeds, obviously, a lot of capacity on the balance sheet and thinking about where that could be deployed going forward between growth or buybacks or what have you. And just any updated thoughts, I guess, as far as incremental West Texas LPG looping or other extensions of the value chain such as LPG export facility in the Houston Ship Channel.

Kevin Burdick:

Yeah. Jeremy, it’s Kevin. The -- as we think about, like we said in the remarks, with -- the Permian volumes have been strong for us. We’ve seen nice growth there. So, clearly, we’re continuing to evaluate and we’ll stay ahead of any capacity needs we had by through our looping of West Texas LPG. So we’ll stay on top of that and won’t get caught short capacity.

Operator:

And the next question will be from Michael Blum from Wells Fargo. Please go ahead.

Kevin Burdick:

Well, Michael, it’s Kevin. As we think about Saguaro, we’ll look at that project from an integrated perspective. I mean you’ve got the contracts with the LNG facility, the potential pipeline in Mexico and our potential pipeline. So all those are related. At the end of the day, the offtakers are the ones that will be looking for the transportation out of Waha. So that’s the way we’re thinking about that. Not ready to talk about any contract terms or rates or anything like that yet. Still early in the process. But we are taking the steps forward and continue to move it forward. So, hopefully, we’ll be in a position to announce something midyear.

Kevin Burdick:

Well, that will all depend on when it -- we would announce something. But again, not ready to talk about any specific capital that might hit, because we’re still unsure when it might be FID.

Operator:

And our next question is from Tristan Richardson from Scotiabank. Please go ahead.

Kevin Burdick:

Well, I think, a lot of the volumes that we’ve seen on our system are growing volumes on contracts that may have been put in place several years ago, back when even pre-COVID. But we also have seen opportunities to go contract new volumes. And Sheridan, do you want to talk about some of the things we’ve seen there?

Tristan Richardson:

Appreciate it, Sheridan. And then maybe just the obligatory high level question. Obviously, strong results in the first quarter. Just thinking about the full year outlook, some of the conditions necessary to hit the high end versus what might need to happen to see the low end occur?

Tristan Richardson:

Appreciate it. Thank you, guys.

Theresa Chen:

Hi. Thank you for taking my questions. Within the G&P segment, can you talk about the fee escalation that I think kind of just wholly steps up in the second quarter now that we’re a month and change through it, how that’s trending now and how that gets to your guidance within the fee range?

Theresa Chen:

Okay. And then in terms of the third-party frac fee, so I understand that you have downsized from the $46 million per quarter as you utilize some of the space on MB-5. But as some of your competitors are also bringing on additional frac capacity second half of this year and into next year, would you expect that the spot fee will also weaken to some extent. So is there further downside even in addition to you being able to use MB-5?

Theresa Chen:

Thank you.

Spiro Dounis:

Thanks, Operator. Hi, guys. First question actually one for about Elk Creek. Curious, you talked about keeping pace with customer needs and I acknowledge this question is probably a bit on the early side. But just given the well connect outlook, potential breathing recovery, GOR is increasing over the next year or so. When is it sort of time to start thinking about not expansion? How are you guys thinking about some of the capital needs and timing that will go into that?

Kevin Burdick:

Yeah. We are with the strength we’ve seen recently and even going back to last year with the activity levels and the producer, the rigs that were there. But particularly now as we move into Q1 and seeing what we have seen from the producers, we’re definitely taking steps that -- are already taking steps necessary to ensure that we’ve got the capacity when we need it.

Pierce Norton:

Well, the short answer to that is yes. This is Pierce. But those things are really driven by customer demands as well, but we definitely are looking for those opportunities. That’s part of the intentionality of the diversification into those more stable earnings type areas in our footprint. So the short answer is yes.

Operator:

And the next question will be from Jean Ann Salisbury from Bernstein. Please go ahead.

Kevin Burdick:

Okay. Jean, this is Kevin. I think the way I would answer that is, I mean, obviously, we -- as we come to a decision to FID or not, that will be -- we’re factoring in what’s going on with the full aspect of the pipeline. And I think it’s safe to say you know us we’ll be do the things we need to do from our contractual position to mitigate that risk as much as we possibly can.

Operator:

And thank you. The next question is from Neal Dingmann from Truist. Please go ahead.

Walt Hulse:

Just, overall, we said we’re 90% fee-based and 10% commodity exposed. And then you think about the G&P business with our POP contracts where some of the direct commodity exposure occurs. We’re well hedged in 2023. So that even reduces that commodity exposure further. So really, it’s a -- when you just look at it on an earnings perspective, it’s a small percentage that we have direct commodity exposure.

Walt Hulse:

You’re talking about the Gathering and Processing the volumes...

Walt Hulse:

…from Rocky Mountain region.

Walt Hulse:

Okay. I mean, yeah, we -- the first quarter, you were at the low end, and if you go to the -- we referenced, we had reached here recently 1.5 Bcf. So we definitely think there’s some -- there’s a ramp and that’s one of the tailwinds Pierce mentioned is where we sit today from a Bakken or Rockies volume perspective, we’re in really good shape.

Operator:

And the next question is from Neel Mitra from Bank of America. Please go ahead.

Walt Hulse:

Sure. Neel, this is Walt. Well, if you back out the gain from the Medford settlement, we’re at 3 -- we are around 3.4 times. So, yes, we’re through 3.5 times, but we’re not meaningfully below it at this point. We are not concerned if that trend is lower. We would -- if we don’t have investment opportunities, we like it probably would trend lower in the short-term. But we continue to look at attractive opportunities. We’ve spoken a little bit about the increases we’re seeing in the various basins and some of the expansion plans that we might need to do on some of the pipes and the like. So those are very, very high return types of projects and that’s where we like to be first. And then we have flexibility for other capital return now that we’re down and achieve these goals.

Kevin Burdick:

Well, Neel, this is Kevin, and I haven’t had a lot of time to talk to our customers over the last couple of days. But, what I would say, you’re right, the rigs have been very sticky. I like that word. As we -- as prices -- if you rewind, rigs really start coming back to the Bakken in earnest as prices move through $50, $55. That’s when we started seeing the stickiness. Now when it ran up to $110, rigs didn’t necessarily follow. But then as the prices came back down, they didn’t go away either. So we still feel very good. It’s not a matter of -- that’s still well above breakeven. Producers are still make -- generating a tremendous amount of cash flow even at the prices we’re seeing on the tape right now. So that would give me a lot of confidence that we’re going to continue to see that stickiness even in this type of environment.

Neel Mitra:

Okay. Great. I appreciate the color.

Sunil Sibal:

Yes. Hi. Good morning, everybody, and thanks for the clarity on the call. So I wanted to start off on Bakken. I think there has been some chatter in the E&P community about well productivity. So I was curious if you could talk about -- in the past you’ve talked about close to 400 wells per year to maintain your gas volumes. I was curious if that number has changed in your view based on some of the recent results and also it seems like gas-to-oil ratio have trended down recently?

Sunil Sibal:

Okay. And then my follow-up was on your Natural Gas Pipeline segment. It seems like a pretty strong Q1 and even if the remainder of the year turns out to be similar to last year. I think you would exceed that guidance. So I was just curious if there are any one-time items in Q1, which helped the gas pipelines?

Sunil Sibal:

Got it. Thanks for that.

Colton Bean:

Hi. Just a quick follow-up on Saguaro. It looks like the proposed 48-inch diameter would offer plenty of capacity over and above the proposed LNG exports in that. So can you speak to how you scope that project and what opportunities you might be tracking downstream apart from LNG?

Colton Bean:

Understood. Thank you.

Craig Shere:

Good morning. Just a couple of quick ones. So the Permian NGL unit rates were shown at about $0.06 versus over $0.06 in the fourth quarter. Wondering if there’s any detail or trending there? And could you remind us roughly on the increments that you can increase Elk Creek with additional pumping and what kind of CapEx that would incrementally run?

Sheridan Swords:

Craig. This is Sheridan here.

Walt Hulse:

That -- again, we’re still working through. That’s the steps we’re taking is to understand exactly what that would be working with power companies, working with pump providers and things like that. So we -- those are the steps. The types of steps we’re taking to ultimately come up with how long it might take. But, yeah, it’s not like building a brand-new pipeline start to finish.

Craig Shere:

All right. Thank you.

Craig Shere:

Understood. And those Permian NGL unit rates?

Craig Shere:

Got it. So no trend going on there, just bouncing around.

Craig Shere:

Thanks.

Andrew Ziola:

Well, thank you all for joining us today. Our quiet period for the second quarter starts when we close our books in July and extends until we release earnings in early August. We’ll provide details for that conference call at a later date. Thank you all and have a good day.

Operator:

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

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.

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.

Operator:

[Operator Instructions]. Today's first question is from Brian Reynolds with UBS.

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.

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.

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?

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?

Operator:

The next question comes from Michael Blum with Wells Fargo.

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.

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.

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?

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.

Operator:

Next question is from Jackie Caleres [ph] with Goldman Sachs.

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.

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, may need to add 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.

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?

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?

Operator:

The next question comes from [indiscernible] with Bank of America.

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.

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.

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.

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?

Operator:

Today's last question comes from Sunil Sibal with Seaport Global Securities.

Walter Hulse:

Yes. Yes, that's a good assumption.

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.

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.

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:

Good day, and welcome to the ONEOK's Third Quarter 2022 Earnings Conference Call and Webcast. [Operator Instructions]. I would now like to turn the conference over to Andrew Ziola, Vice President of Investor Relations. Please go ahead.

Pierce Norton:

Thanks, Andrew. 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, the 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, our Senior Vice President of 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 guidance midpoints 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 in some of the most highly productive U.S. shale basins, and 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 in a favorable commodity price and increasing demand backdrop. So with that, I will turn the call over to Walt for a discussion of our financial performance and the expectations and our insurance update. So Walt?

Kevin Burdick:

Thank you, Walt. 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 incentivized ethane on our system. Volumes have remained strong in the region with September averaging more than 380,000 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 the recent third-party plant connection 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 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 ONEOK, 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 in partial recovery and the Rockies continuing to provide opportunities to incentivize recovery. Construction continues on our 125,000 barrel per day MB-5 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 remained 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. 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 led us adjusting our volume expectations for 2022 to be near or slightly below the guidance range. There are currently more than 40 rigs and 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 to 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 Demicks Lake III 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. In the Mid-Continent region, we continue to see increased activity with 4 rigs now operating on our acreage and more than 50 rigs basin-wide. 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 NGLs to our system. In the Natural Gas Pipeline segment, 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 service 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 Pierce, 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 project is expected to cost $95 million and be completed in the third quarter of 2023 and is included in our outlook. Pierce, that concludes my remarks.

Operator:

[Operator Instructions]. The first question today comes from Brian Reynolds with UBS.

Kevin Burdick:

Brian, this is Kevin. I'll start and then Sheridan 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 in all of our basins with the tailwinds, with the existing rigs we're seeing today as those carry over into '23. So volume growth is going to be the primary driver. You've also got -- you're going to have a full year of 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 hedge prices we have in '23 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 '22. As we mentioned, full recovery we expect out of Permian, partial in the Mid-Continent, and we'll continue to incentivize ethane out of the Bakken, where appropriate.

Brian Reynolds:

Great. I appreciate that color. Maybe just to pivot towards capital allocation for a minute. ONEOK is trending towards its leverage target and payout ratio targets. Obviously, there are some concerns that were partially alleviated with earnings around the insurance proceeds. But I was curious of how we should think about the return of capital framework looking into '23 given that you've had the same dividend since 2019, but that said, never cut at the same time. So any color there, I appreciate it.

Operator:

The next question comes from Michael Blum with Wells Fargo.

Kevin Burdick:

Yes, Michael, it's Kevin. For your first question, we estimate there's still probably 300 million to 400 million a day of gas coming from Canada. That will continue to get displaced from Bakken as Bakken grows. So you've 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 that's going out south that doesn't go to Northern Border. So that's going to help. So we don't think there's one single solution that provides -- that's going to provide that, but we do believe we'll be able to find and there will be the necessary capacity out of Basin as we move forward.

Sheridan Swords:

No. I mean, there will be a little bit of an impact on that if we build down in Mont Belvieu if you put down in there. But today, or when Medford was up, most of our liquids was transported down Sterling anyway to the Mont Belvieu market. So we think overall, the market dynamics are not going to be impacted that much, whether we build it at Medford or at Mont Belvieu.

Jean Salisbury:

In the third quarter, there was more ethane recovered from the Rockies and less from the Mid-Con than I would have expected. Is it fair to say that most of the time you would recover marginal ethane from the Mid-Con before the Rockies and that maybe it was specifically due to AECO price blowouts in the quarter that it was a little flipped from usual?

Jean Salisbury:

Okay. That's helpful. And assuming that Bakken does go back to higher rejection in the next couple of quarters, I think the Northern Border Btu spec at that receipt point is probably going to exceed the 1,100, which I think Northern Border has said, is kind of the max that they really want. Does anything happen then? Or is that just all kind of a whole FERC process to potential cap in?

Operator:

The next question comes from Jeremy Tonet with JPMorgan.

Walter Hulse:

Well, as we said on the last call, the coverage that we have is that we are entitled to receive coverage so that we get return to what we would have made, but for this event. So it's system-wide. So if that does impact other parts of the business like optimization and marketing, that gets factored into our BI calculation. The money that we received in September, [indiscernible] that we booked in September, I wouldn't necessarily look at as a run rate because there's still are some moving parts that we're working with the insurance companies to refine how we look at BI going forward. Those costs were predominantly the third-party frac costs. And as we work with them and refine how much optimization in the market, we do expect to receive some benefit from that going forward. In 2023, we expect BI coverage to continue. And at that point, be on a pretty regular month-to-month catch up so that we're hoping that you really don't see any real variation from the BI insurance going forward.

Kevin Burdick:

Yes, Steve, it's Kevin. Yes, MB-5 was a significant mover in moving some of that capital forward into '22. We also had a compressor station up north in the Bakken that we moved forward with that will add to our growth in '23. 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 -- strong earnings power from them, and that will contribute in '23 as well. So just a combination of those factors are what led into the increase in '22. You're thinking about '23 correctly. If -- once we complete MB-5 and Demicks Lake III, that would lead you probably to a little step down in capital barring other projects that we continue to work on that could prove. So that's the unknown at this point is we're constantly working on new projects that -- and as they reach FID, we'll announce them. But absent those, then yes, you would expect CapEx to maybe come down a little bit in '23.

Theresa Chen:

First, I would love to touch on the 2023 guidance and delve 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, any color you can share on assumptions for rig counts, well completions, exit-to-exit growth in oil or gas? And then granted that the ethane recovery dynamic remains in development and can be volatile, but any sort of color you can give on the recovery assumption in 2023 versus the level that you just reported for the third quarter 2022?

Theresa Chen:

Got it. And in the Gathering and Processing segment, that $1.16 average fee rate, quite a step-up from the previous run rate and I understand the color you shared on the fee escalators and the composition of it. 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 similar magnitudes of step-ups? Or generally speaking, how should we think about this line?

Operator:

Next question comes from Michael Cusimano with Pickering Energy Partners.

Sheridan Swords:

Michael, this is Sheridan. Yes, Medford did have an impact on those numbers, and that's factored in there. And that 45-day waiting period, we did take some hits in optimization and marketing there. And as you mentioned, the other things we have is spreads were a little bit narrowed during that time. We had forward sales due to Medford, that we push forward sales forward, that we will receive some of that money or $17 million of that money in the first quarter and second quarter -- I'm sorry, fourth quarter and first quarter as we go forward here, we will get that $17 million back. So that -- those are the 3 main factors as you see in that drop in optimization and marketing.

Pierce Norton:

We do. 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 because that's on us. But going forward, we expect to get any losses in marketing and optimization that we would have received if Medford had been up, we expect insurance to cover that.

Kevin Burdick:

Michael, we're not going to provide kind of 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 weather into play. So that's why we backed off that.

Walter Hulse:

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 210,000 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 to build it wherever we want to do that, and that's what we're still considering at this point. Going forward, we would expect to likely not get as much -- not get unallocated money. This was -- it should be allocated out for the BI 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 repair or replacement of the facility.

Walter Hulse:

No. MB-5 is its own stand-alone project that we built because we needed it. And -- we -- obviously, it will help us a little bit as it comes on and we are going to be in our natural ramp-up phase. But that is part of our capital and the proceeds that we received for the repair or replacement of the Medford facility will be discrete, and it will cover those costs.

Andrew Ziola:

All right. 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.

Operator:

Good day, and welcome to the Second Quarter 2022 ONEOK Earnings Call. This conference is being recorded. At this time, I would like to turn the conference over to Mr. Andrew Ziola, Vice President, Investor Relations. Please go ahead, sir.

Pierce Norton:

Thanks Andrew. Good morning, everyone. And thank you for joining us today. We appreciate your interest in investment in our company. On today's call is Walt Hulse, 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 of Natural Gas Liquids and Natural Gas Gathering and Processing; and Chuck Kelley, our Senior Vice President of Natural Gas Pipelines. Yesterday, we announced strong second quarter 2022 earnings, provided an update on the Medford incident and affirmed our 2022 financial guidance expectations. As we sit today, we still expect to achieve the midpoints of our 2022 net income and adjusted EBITDA guidance, which Walt will provide additional details shortly. Our second quarter financials were achieved despite unseasonable weather in the Rocky Mountain region during the quarter. Two separate April weather events cause widespread outages and power, disrupting midstream and producer operations across the region. Our employees were well prepared and quickly responded to the challenge. They remained focused on the safe operation of our assets and the safety of the communities where we operate. And they worked with local agencies, customers, utility providers to resume normal operations as quickly as possible. Across our operations, we continue to see strength in producer activity, with commodity prices and demand supporting a strong second half of the year. While it is still too early to provide our outlook for 2023, we are well positioned across our integrated footprint to help transport and process essential natural gas and natural gas liquids. Before I turn the call over, I'd like to make and provide an update on the Medford, Oklahoma fractionation facility. On Saturday, July 9, mid-afternoon, there was a fire at the facility. First and foremost, all of our personnel were safe and accounted for, the safety of our employees and communities is always the main concern and initial focus during a situation like this. I would like to thank the many employees, first responders and local agencies who worked together to quickly respond to the incident. We cannot see enough about the corporation and the coordination efforts of those teams who work to put a safety of our personnel and the surrounding community first. We are incorporating with government agencies as we work to determine the cause of the incident, but expect the facility to remain out of service for an extended period of time. In yesterday's earnings release, we provided details of our property and business interruption insurance coverage. Because of this coverage, we do not currently anticipate that the incident will have a material effect on our financial condition. Results of operations or cash flows, however, the timing of insurance proceeds may impact financial results in a given quarter or year. From an operational perspective, we continue utilizing our system of integrated NGL pipeline, fractionation and storage assets. We're also working with industry peers on additional fractionation and storage arrangements. I want to thank those companies for working with us to keep these essential products flowing since the incident. Our industry has a long history of stepping up to help each other when disruptions happen. And this incident has once again proven that relationships in corporation are critical to this industry's long-term success. And we want to thank them once again. With that, I will turn over the call to Walt for discussion on our second quarter financial performance.

Kevin Burdick:

Thank you, Walt. During the second quarter, we saw NGL volume growth across all our operating regions compared with the first quarter 2022. NGL volume expectations remain strong through the remainder of the year, providing confidence in achieving the midpoint of our raw feed throughput guidance for 2022. Natural gas processed volumes and well completions during the quarter were significantly impacted by the April weather events. And we now expect process volumes to be toward the lower end of our 2022 volume guidance range. Let's take a closer look at our Natural Gas Liquids segment. Total NGL raw feed throughput volumes increased 5% year-over-year and 4% compared with the first quarter 2022. Rocky Mountain region NGL volumes increased 10% year-over-year and 5% compared with the first quarter 2022. Activity in the region has rebounded following the April storms, as July volumes averaged more than 360,000 barrels per day, 9% higher than the second quarter average. Mid-Continent NGL volumes increased 4% compared with the first quarter 2022, driven by increased C3+ volumes as producers continued to add rigs in the basin, with a large majority of the region's NGLs dedicated to ONEOK system. In the Permian Basin, NGL volumes increased 10% year-over-year and 4% compared with the first quarter 2022. We recently completed a 25,000 barrel per day expansion on a portion of our West Texas NGL pipeline in the basin to support continued expected volume growth. We saw increased ethane volumes on our system in the second quarter 2022, and expect continued opportunities for ethane to be recovered through the remainder of the year. We anticipate high levels of recovery in the Permian Basin, periodic recovery in the Mid-Continent and continued opportunities to incentivize ethane recovery in the Rocky Mountain region as in basin natural gas prices fluctuate. Our fractionation capacity is fully utilized following the incident at our Medford Facility. And as Pierce mentioned earlier, we have worked with industry peers to secure additional fractionation and storage capacity. Medford’s capacity was approximately 210,000 barrels per day of our total system-wide name plate capacity of more than 980,000 barrels per day. Construction continues on our 125,000 barrel per day MB-5 fractionator in Mont Belvieu, which we now expect to be complete early in the second quarter of 2023. Moving on to the Natural Gas Gathering and Processing segment. In the Rocky Mountain region, second quarter processed volumes averaged more than 1.2 billion cubic feet per day, a slight decrease compared with the first quarter 2022 due to the April weather. We’ve seen recent volumes return to pre-storm levels. And in July, volumes reached approximately 1.4 billion cubic feet per day. Through the first six months of the year, we’ve connected 157 wells in the region and we continue to expect approximately 375 to 425 well connections in the region this year. There are currently approximately 45 rigs and 18 completion crews operating in the basin with 21 rigs and approximately half the completion crews on our dedicated acreage. Basin-wide rigs have more than doubled in the last 12 months from only 20 rigs total in July 2021. 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 in 2023, compared with 2022 if these activity levels remain. The basin-wide DUC inventory remains at approximately 500 with half of those on our dedicated acreage. This compares with approximately 650 DUCs in a basin a year ago. Recent producer M&A in the Williston Basin continues to show the value and long-term viability of the play. We see these recent announcements as positive for ONEOK, as we expect increased activity from the acquirers to drive NGL and natural gas volumes to our system. In the Mid-Continent region, we continue to see increased activity with four rigs now operating on our acreage and 46 rigs basin-wide. We expect steady to increasing activity through the remainder of the year with the majority of rigs basin-wide driving additional NGLs to our system. In the natural gas pipeline segment, strong second quarter results benefited from the continued increasing demand for natural gas storage and transportation services. Last quarter, we discussed a recently completed 1.1 billion cubic feet 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 early 2023, and is nearly 90% subscribed through 2029. We also recently completed two open seasons for additional pipeline capacity to address increase demand. One on our WesTex pipeline system in the Permian Basin, and one on our Viking pipeline in the Upper Midwest. Both open seasons were successful and we planned to move forward with low capital expansions on both systems. The value of our natural gas pipelines and storage assets continue to be highlighted in the outperformance we’ve seen from this segment so far this year. Pierce, that concludes my remarks.

Operator:

Thank you, sir. [Operator Instructions] We will take the first question from Jeremy Tonet from JP Morgan. Your line is open. Please go ahead.

Pierce Norton:

Hey, good morning, Jeremy.

Pierce Norton:

So Jeremy, I think I’ll let Walt take the materiality question for us and then we’ll flip it over to Kevin and Sheridan on the offloads.

Kevin Burdick:

Yes, Jeremy, it’s Kevin. On the volumes and where they’re going right now, I mean, clearly a lot of them are going down to Belvieu. We talked in our remarks about our industry peers that have been very helpful in securing spots for those barrels. We feel good about being able to move the volume. Especially as we get to MB-5 and keep in mind, that’s going to be another 125,000 barrels a day of new capacity that will come online early in the second quarter. So that’s the things we’ve got lined up there. And again, we feel good about being able to move the volumes.

Jeremy Tonet:

Got it. That’s helpful. Thank you for that. And just want to pivot over towards IROF if we could and realize it’s hot off the press, and it seems like the shape keeps changing a bit here and what the bill looks like. But just wondering thoughts you could provide as far as how as it currently stands this might impact your tax profile in 2023 or going forward. And as the bill is written right now, separately, would this increase or change your appetite to pursue CCS, renewables or other items like that?

Walt Hulse:

And so I’ll take the question about CCUS. I’d like to remind everybody on the call that 36% of the natural gas demand in this country is devoted to electricity. You add to that 33% in the industrial sector. So that’s a total of almost 70% of the natural gas demand goes to those two forms of consumption. Anything that is done that would enhance the ability to capture carbon from natural gas being consumed is a good thing for our industry. And so these incentives, it’s left to be seen exactly how effective they’re going to be, because we need to know the details, but it does encourage us as an industry and as a producer of natural gas and actually, the liquids that are coming off the oil production and the natural gas production in these rich basins that this will help to curb the CO2 emissions in the future. And we do think that will open up some opportunities that we will look both at CCUS and hydrogen. So I think it’s a positive for the industry what’s happening.

Operator:

We will take the next question from Brian Reynolds from UBS. Your line is open. Please go ahead.

Kevin Burdick:

I mean, I’ll start Brian. This is Kevin. I think the base business is performing very well. If you think about where we were going into the storms, we were right on track with everything that we had kind of outlined and laid out. The storms up in the Bakken did kind of set the basins back a couple months, not just with the volumes flowing, but also it was kind of a couple months pause on lower completions that we saw. So it kind of delayed things, and that’s the reason that we’re going to be at the lower end of the guidance from a volumetric perspective there. But on the flip side, when you look at the NGL business and what they’ve done both from a earnings perspective, as well as a volumes perspective, and then the outperformance of the gas pipeline business, I think those two segments are performing at or better than we anticipated coming into the years. So I think it sets us up nice going into to 2023.

Kevin Burdick:

Brian, you hit it on the head. We’re still really early in that process. And, and again, not ready to talk about timing or anything like that. We’ve got capacity secured, we believe to move our volumes and we’ll keep working that until we get more information.

Kevin Burdick:

Thank you.

Michael Blum:

Thanks. Good morning, everyone. So apologies for maybe a technical question. But just so I understand, are you going to be accruing insurance proceeds in your EBITDA results in Q3 and Q4? So that’s how guidance is basically unchanged or is that not the case and you’re just able to make it up in other areas.

Michael Blum:

Okay, great. Thanks for that clarification. Also just wanted to ask about AECO gas prices, which are big trading at a pretty big discount to Henry Hub. Can you just remind us how your ethane recovery economics in the Bakken work? Will you benefit any way from the decline in AECO gas prices? Thanks.

Michael Blum:

Got it. Thank you.

Colton Bean:

Good morning. So the NGL segment had a fairly significant step up in costs. Of the three drivers you mentioned, I think fuel power and then third party services. Do you expect an improvement in the back half of the year for any of those or is Q2 level of pretty good run rate moving forward?

Colton Bean:

Understood. And then just following up on the Bakken ethane discussion, I mean, it sounds like, with the wider gap between AECO and Mont Belvieu pricing this quarter. Would you expect any upside to that bundled rate? Just if you – if the incentive rate that you have to offer is now less of a discount than it would’ve been previously.

Colton Bean:

Got it. Appreciate the time.

Theresa Chen:

Hi. I just wanted to ask first on the $16.4 million increase in the NGL segment related to higher average fee rates. Can you tell us what that was related to precisely and is that expected to carry forward?

Theresa Chen:

Okay. Thank you. And in your GMP segment, the $5.3 million increase due to the contract settlement during the quarter. Should we expect some sort of offset and base earnings going forward as a result?

Theresa Chen:

Thank you.

Michael Lapides:

Hey guys. Thank you for taking my question and congrats on a really good quarter. Just curious as you think about infrastructure needs going forward, given kind of some of the volume commentary about July volumes, how are you thinking over the next year or so about the need for either new processing or even a sixth frac at Belvieu?

Michael Lapides:

So then, if there’s not really a need potentially, I mean, volumes could always surprise to the upside. But if there’s not really any need for any material new asset development in 2023, that implies that the capital budget kind of declines a ton, which not a surprise. How are you and how are the Board – how’s the Board kind of thinking about capital allocation and uses of some of that significant free cash flow that you might be generating next year?

Michael Lapides:

Got it. Thanks guys. Much appreciate it.

Chase Mulvehill:

Good morning. I wanted to come back to the GMP side of the business, and I guess a few questions. I guess just correct me if I’m wrong and I think your commodity or POP exposure is 15% to 20% this year. And then maybe just remind us again, the gas versus NGL exposure on those POPs and how much you have hedge versus open today? And then just maybe tie into there, kind of what you’re thinking about realized GMP rates in the back half of the year?

Chase Mulvehill:

Is it fair to assume in 3Q that a lot of your open volumes were natural gas as opposed to NGLs?

Chase Mulvehill:

Okay. All right. If we go up to the NGL section and look at volumes and kind of where they are today, I think you said, 360,000 barrels a day. If we go back and look back in April, you were doing 385,000 a day. So we’re not back to kind of April peak-ish levels, but yet GMP volumes in the Rockies are actually back to peak levels. So kind of help me connect the dots there. Is that Medford related or is there something else, and should we kind pretty quickly back to that 385,000?

Chase Mulvehill:

Okay. All right. Last one, just going to squeeze one more and I apologize. Just want to confirm this. It sounds like, obviously you’re seeing – looking at Medford and trying to figure out when you can bring it back online. But I just want to confirm that it is not a total loss. You do not see it as a total loss at this point. Correct?

Chase Mulvehill:

Okay. Got it. Makes sense. I’ll turn it back.

Craig Shere:

Good morning. Congrats on the quarter. One clarification on Medford. So as far as new expense for third-party fractionation or things that were contracted, you ultimately get insurance recoveries, but doesn’t this kind of at least limit optimization margin opportunities until something’s resolved?

Craig Shere:

Okay. And maybe this is expressing my own ignorance and I apologize. Given the increased gas storage and storage pricing, I’m kind of assuming storage is more of a steady year round product versus gas pipes that have more seasonality since the storage has to fill. So if that’s the case, does the improving storage position in terms of capacity and pricing, reduce your gas height seasonality?

Craig Shere:

Got you. So the increasing contribution of storage really doesn’t impact seasonality.

Craig Shere:

So the fact that you’re increasing the amount of storage and the pricing is looking more attractive that doesn’t have any impact on the seasonality question?

Pierce Norton:

So, Craig, the only thing I’d add to that, this is Pierce, is post Winter Storm Uri, the value of storage has increased. And so we do have customers that lay that seasonal spread and that benefit goes to them. But we also have utilities that are putting gas into storage every single month during the summers getting ready for that winter pull that they have during their peak demand from basically December through March.

Operator:

Next question from Jean Ann from Salisbury, sorry, Jean Ann Salisbury from Bernstein. Your line is open. Please go ahead.