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spk02: Good day and welcome to the One Oak third quarter 2022 earnings conference call and webcast. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on a touch-tone phone. To withdraw your question, please press star, then two. Please note, this event is being recorded. I would now like to turn the conference over to Andrew Viola, Vice President of Investor Relations. Please go ahead.
spk08: Thank you, Betsy, and welcome to OneOaks' third quarter 2022 earnings call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. After our prepared remarks, management will be available to take your questions. Statements made during this call that might include One Oaks expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. Just a reminder for Q&A, we ask that you limit yourself to one question and one quick follow-up in order to fit in as many of you as we can. With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer. Pierce?
spk09: 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 Kelly, 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 US 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'll turn the call over to Walt for our discussion of our financial performance and the expectations and our insurance update. So Walt.
spk11: Thank you, Pierce. One Oaks third quarter 2022 net income totaled $432 million or 96 cents per share. a 10% increase compared with the third quarter 2021, and a 4% increase compared with the second quarter. Third quarter adjusted EBITDA was $902 million, a 4% year-over-year increase, and an increase from the second quarter. Higher results benefited from increased Rocky Mountain region NGL and natural gas volumes, higher realized commodity prices, net of hedging, and higher average fee rates. Additionally, we had lower interest expense due to our lower debt balances and increased capitalized interest. Third quarter 2022 results reflected our $5 million property insurance deductible related to the Medford incident and approximately $30 million of losses related to the 45-day business interruption waiting period under the terms of our insurance policy. We received notice in September that our Medford property insurers agreed to pay $100 million unallocated first installment of insurance proceeds. And as of today, we received $45 million of that amount and expect to receive the remaining amount before year end. We've applied this cash received to our outstanding insurance receivables. After the waiting period ended, we incurred a costs subsequent to the 45-day business interruption waiting period of $21.7 million, primarily related to third-party fractionation agreements, and recorded a partial impairment charge of $6.7 million, representing the value associated with certain Medford facility property based on the limited assessments completed to date. There is no income statement impact of these incurred business interruption costs or impairment charges as they are fully offset by insurance receivables. We continue sharing information with our insurance carriers to refine ongoing business interruption insurance coverage and to determine the ultimate path to replacement of this temporary loss of fractionation capacity. We will provide additional updates as we move forward in this process when material information is available. And lastly, for the third quarter, we ended with higher NGL inventory levels that have since been sold forward, and we will realize $17 million earning benefit from those sales in the fourth quarter and first quarter of 2023. As of September 30, our net debt to EBITDA on an annualized run rate basis was 3.8 times. and we continue to view 3.5 times or lower as our long-term aspirational goal. We currently have no long-term debt maturities until September of 2023, and we have no material exposure to floating interest rates through our current outstanding long-term debt. Yesterday, we affirmed our 2022 guidance midpoints of $1.69 billion for net income and $3.62 billion for adjusted EBITDA. We now expect total capital expenditures of $1.2 billion driven by our acceleration of spending on the MB-5 fractionator and smaller scale expansion projects that were not previously planned for 22 across our three business segments that will contribute to growth in 2023. Key drivers for our 2023 outlook of a more than 10% increase compared with our 2022 midpoints to exceed $4 billion in adjusted EBITDA include continued strength in fee-based earnings and rates, stable to growing producer activity providing higher natural gas and natural gas liquids volumes in our system, and expected higher realized commodity prices due to higher hedges. These tailwinds into 2023 from our base business, additional insurance recoveries related to Medford, and our strong financial position provide us confidence in our double-digit earnings growth outlook for next year. I'll now turn the call over to Kevin for a commercial update. Thank you, Walt.
spk10: Let's start with our natural gas liquid 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 a 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 in to our 2022 and 2023 expectations. As we sit today, we are seeing ethane and ethylene inventories starting to get worked off, which we believe will lead to increasing demand in 2023. As for One Oak, it is typical that we don't incentivize as much ethane out of the Bakken during the winter season due to higher natural gas prices and natural gas demand. But we will continue to be opportunistic. As it relates to our 2023 outlook, we expect the Permian to be in full ethane recovery, the Mid-Continent to be in partial recovery, and the Rockies continuing to provide opportunities to incentivize recovery. Construction continues on our 125,000 barrel per day MB5 fractionator in Mont Bellevue. which we still expect to be completed early in the second quarter of 2023 and is reflected in our updated 2022 capital guidance. Moving on to the natural gas gathering and processing segment. Producer activity remains strong in the Rocky Mountain region with third quarter processed volumes averaging 1.4 billion cubic feet per day, a record quarter for us. Our average fee rate also increased, reflecting the impact of contract escalators, higher volumes on higher fee component contracts, and a larger percentage of our total volumes from the Rockies. On a go forward basis, we expect this average rate to range between $1.10 and $1.20. Year to date, we've connected 244 wells in the region. We now expect to complete approximately 375 well connections near or at the low end of our guidance due to the impact of the April storms, timing of some wells coming on, and availability of completion crews and materials. 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 can maintain natural gas production at current levels, but with more than 20 currently on our acreage, we expect to see higher well connections and volumes in 2023 compared with 2022. The 200 million cubic feet per day Dimex 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 duck inventory remains 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 four 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 to $430 million. We are highly subscribed for our storage services in Oklahoma and Texas at higher rates and for longer terms, including our recent expansion of our Texas storage facilities, which is now fully subscribed through 2032. Additionally, we are expanding our storage capabilities in Oklahoma, enabling an additional 4 billion cubic feet of storage capacity to be contracted. This project is expected to be complete in April 2023 and is nearly 90% subscribed through 2029. And we are also evaluating an additional expansion of our Texas storage assets. And lastly, before I turn the call back to 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.
spk09: Thank you, Walt and Kevin. As we enter the last couple of months of 2022 and look forward to the next year, I'm proud of our employees and want to thank them for their hard work and contributions to continue to focus on operating safely, sustainably, and environmentally responsible, and are key to our success as a midstream operator. How we operate is important, but also how we engage with our employees, communities, and other stakeholders is equally as important. Also important for One Oak is to remain focused on meeting the growing energy demand for today even as it looks forward to helping drive the energy transformation needs for the future. We also recently announced that One Oak joined with two other large publicly traded companies based in Oklahoma and a venture capital firm to fund an effort to transform Oklahoma into a hub of energy technology startups and redefine a sector that has shaped the region's economy for more than a century. We believe this partnership aligns to our long-term business strategy, which includes potential low-carbon investments that contribute to long-term growth and business diversification. One Oak has been building the right teams and resources to better participate in the innovative practices and technologies that it sees now and those that may play a role in the future. Before I turn the call over for Q&A, I wanted to highlight an important ESG item we mentioned in our earnings release. One Oak's MSCI ESG rating was recently reviewed and updated by MSCI to AAA from AA, and we maintained our industry leader status. As I previously said, our ESG efforts are a source of pride for One Oak, and we are committed to continuing to make progress in these important areas. With that operator, we're now ready for questions.
spk02: We will now begin the question and answer session. To ask a question, you may press star then one on your touch tone phone. If you are using a speaker phone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, Please press star, then two. At this time, we will pause momentarily to assemble our roster. The first question today comes from Brian Reynolds with UBS. Please go ahead.
spk07: Hi. Good morning, everyone. Good morning. Maybe to revisit some of the assumptions in your prepared remarks around 23 earnings growth, it seems like we should see some tailwinds on volumes and hedges rolling higher. But I was curious if we could just dive a little bit further into the ethane recovery assumptions for 23. Historically, you guys have been pretty conservative on this assumption, but curious of how we should think about how BTU concerns plateauing ethane demand for the next few years and permeating that gas tightness impacted some of your assumptions as it relates to Rockies recovery into 2023 and that 10% earnings growth. Thanks.
spk10: Hey, 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 know, 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 to 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 the Permian partial in the mid-continent, and we'll continue to incentivize ethane out of the Bakken where appropriate.
spk06: You know what I would add on that is when we look at 23, as we looked in 22, we have limited incentivized ethane coming out of the Bakken factored in. We really see that as an opportunistic opportunity going forward.
spk07: Great. I appreciate that color. Maybe just to pivot towards capital allocation for a minute. One Oak is trending towards its leveraged targets and payout ratio targets. Obviously, there's some concerns that we're partially alleviated with earnings around the insurance proceeds, but was curious of how we should think about the return of capital framework looking into 23, given that you had the same dividend level since 2019, but that's never cut at the same time. So any color there. I appreciate it. Thanks.
spk09: So, Brian, this is Pierce. You know, with our positive earnings growth indications for 2023, our payout ratio and our debt to EBITDA metrics are indicating that we are going to have more flexibility to execute on one or more of the capital allocation levers that are going to be available to us to create that value for our shareholders as we progress through 2023. So that's the way I'd answer your question there.
spk07: Great. Fair enough. I'll leave it there. Have a great rest of your morning. Thank you, Brent.
spk02: The next question comes from Michael Blum with Wells Fargo. Please go ahead.
spk05: Thanks. Good morning, everyone. I wanted to ask on the latest on northern border, where does it stand in terms of gas coming from Canada versus the Bakken? Is there any more room there? And then related to that, Any updates on a potential expansion project on the northern border?
spk10: Yeah, Michael, it's Kevin. For your first question, you know, we estimate there's still probably 300 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, um, on various residue takeaway, um, and demand projects, actually some demand projects in basin. Uh, we have secured, uh, about a hundred million a day of takeaway solution on WBI that's going out South that doesn't go to Northern border. So that's going to help. Um, so we don't think there's one single solution, um, 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 the basin as we move forward.
spk05: Okay, thanks for that. I guess second question, just wanted to ask, I know you haven't really made a decision yet about whether you're going to rebuild Medford or maybe build something else at Montpelier or otherwise, so just Sherry, if you could talk through the dynamics. If you do choose to not rebuild Medford, does that change anything in terms of the market dynamics between Conway and Mount Bellevue for you as it relates to Sterling?
spk06: No, I mean, there will be a little bit of an impact on that if we build down in Mount Bellevue because you put more down in there. But today... Or when Medford was up, most of our liquids was transported down Sterling Inway to the Mont Velvie 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 Velvie.
spk05: Great. Thanks so much.
spk02: The next question comes from Jean Ann Salisbury with Bernstein. Please go ahead.
spk03: Hi, good morning. In the third quarter, there was more ethane recovered from the Rockies and less from the MidCon than I would have expected. Is it fair to say that most of the time you would recover marginal ethane from the MidCon before the Rockies and that maybe it was specifically due to ACO price blowouts in the quarter that it was a little flipped from usual?
spk06: Yes. We look at the gas basis as really what kind of drives us on which basin we're going to incentivize. So, yeah, ACO pricing versus what's going on in the mid-continent will drive where we incentivize ethane coming out of there. We did see a lot of benefit in the third quarter coming out of the Rockies due to the basis and what we could secure gas prices for and sell them for ethane. So we see that as a great opportunistic two basins that we can incentivize at times and kind of play that gas basis between the two. So we think that's a big advantage to our system.
spk03: Okay, that's helpful. And assuming that Bakken does go back to higher rejection in the next couple quarters, I think the northern border BTU spec at that receipt point is probably going to exceed the 1100, 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 put an actual cap in?
spk10: Keenan, this is Kevin. Yes, as you reject more ethane, that will raise the BTU content on northern border. If you were back to about where we were pre-COVID and that number was north of 1100, right now there is not a spec on the pipe. The northern border, it's our understanding, they'll watch it. They've got some levers to pull if it gets too high and downstream markets start to have concerns. They continue to work with shippers and all the relevant stakeholders to potentially go back to FERC for a spec, but we don't have an exact timing on that. So we'll watch it. If it gets to the point where it gets, the BTU level gets too high and downstream markets start, you know, raising issues, then we always have the option to recover ethane to lower it back. And if we do that, if it's required at that point, then that would require, I mean, that would be at full rates, not at an incentivized rate.
spk03: Great. That's all for me. Thank you.
spk02: The next question comes from Jeremy Tana with JPMorgan. Please go ahead.
spk00: Hey, good morning. This is Steve McGee on for Jeremy. Just starting along the insurance line, as far as business interruption insurance goes, just trying to get an idea of what's covered under that. Does that include optimization, marketing in there as well? And then for 2023, does that include the business insurance as well?
spk11: 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 returned 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 a road that we booked in September, I wouldn't necessarily look at as a run rate because there still are some moving parts that we're working with the insurance companies 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 and marketing we do expect to 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.
spk00: Understood. Thank you. And then I guess flipping over to CapEx, you pulled some forward. Well connects kind of towards the lower end of the guide, but still up a little bit this year. So I'm guessing most of the uptick this year is the MV5. Should we expect, I guess, a little bit less CapEx into 2023 now because of that? And just if you could walk us through, I guess, that that raise this year and then what that looks like in the next year as well.
spk10: Yes, Stephen, this is Kevin. Yeah, 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 our opening remarks. And then we just had a handful of smaller routine growth type projects that typically have extremely strong multiple or strong earnings power from them. And that'll 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, if, you know, once we complete MB5 and Deming Slate 3, you know, that would lead you probably to a little step down in capital, barring other projects that we continue to work on that could be approved. That's the unknown at this point is, you know, we're constantly working on new projects that, and as they reach FID, we'll announce them. But absent those, then, yeah, you would expect CapEx to maybe come down a little bit in 23. All right.
spk00: Great. Thank you. I'll leave it there.
spk02: The next question comes from Teresa Chen with Barclay. Please go ahead.
spk01: Hi there. Thank you for taking my question. 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 of assumption in 2023 versus the level that you just reported for third quarter 2022.
spk10: Teresa, this is Kevin. We're not, again, we're not going to get into the detailed guidance specifics that we'll release probably sometime early next year. But I would tell you as we think about price decks and activity levels, there's probably more rig, if you just look at today, there's more activity in the basins that we're looking at, that we're talking about, than we have in that outlook. So The activity levels we're seeing today are plenty strong to help us achieve that exceedance of $4 billion.
spk01: Got it. And in the gathering processing segment, that $1.16 average fee rate, quite a step up from the previous run rate. I understand the color you shared on the fee escalators and the composition of it. Just trying to, you know, think about the trajectory of growth here, was there anything in particular driving this? And as we think about fee escalators in 2023 and beyond, should we assume similar magnitudes of step-ups or, you know, generally speaking, how should we think about this line?
spk06: Teresa, this is Sheridan. When you think about that margin, what's the drive in that increased step up? A lot of it was on escalation is where it came from. Some on the contract mix being on, we got volume on higher contracts or more margin contracts and on others as we go forward. The big thing that's going to drive as we get into 23, a key being that trajectory is what the inflationary escalators are going to be. And we'll have to see how inflation comes out and how the You know, we go against CPI most of the time on that, how CPI reacts in 23 versus 22 is going to be a big driver on where we land on that and going forward. So it's really going to be based on inflation, be the biggest piece.
spk01: Thank you.
spk02: The next question comes from Michael Cusiano with Pickering Energy Partners. Please go ahead.
spk04: Hi, good morning, everyone. I wanted to first focus on the natural gas liquids optimization and marketing number. I think you all noted a 44 million decrease sequentially. Was any of that a result of Medford at all, or was it just other, you know, I think you all mentioned some price differentials and timing on the NGLs?
spk06: Michael, this is Sheridan. Yeah, Medford did have an impact on those numbers, and that's factored in there in that 45-day waiting period. We did take some hits in optimization and marketing is there. And as you mentioned, the other things we have is, you know, spreads were a little bit narrow during that time. We have 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'll get that 17 million back. So those are the three main factors as you see in that. drop in optimization and marketing.
spk04: Okay, and just to clarify, you would expect to be, in the future, you would expect to be, or you would expect to recoup insurance proceeds in the event of any optimization and marketing reductions? We do.
spk06: We do expect to get insurance proceeds, but a lot of that $45 million, 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.
spk04: Okay. That is helpful. And then previously you all have given like a current month run rate out of the Bakken for NGL takeaway. I think you gave a September number. Any indication you can have for what October looks like going forward?
spk10: Michael, we're not going to provide kind of numbers in Q4. We gave you the number for September. 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.
spk04: Okay, understood. And then last one, if I can. If I break up the insurance proceeds from one allocation for business interruption and the other for property loss, are you all viewing the property loss as – you know, replacement cost or is it, um, you know, getting back the frac capacity to where like MV, MV five recover some of that. Um, just trying to think of like how that shapes out, um, from the way you and the insurance company are, are thinking about it.
spk11: No, we, 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. 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 unallocated money. 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.
spk04: Okay. That's helpful. Would MB5, since it was already undergoing construction, be something that you could allocate any sort of property loss to? Or would it be in, you know, MB6 and beyond, if you wanted to?
spk11: No, MB5 is its own standalone project that, you know, we built because we needed it. And, you know, obviously it'll help us a little bit as it comes on and we were going to be in our natural ramp up phase. But that is part of our capital and The proceeds that we receive for the repair or replacement of the Medford facility will be discreet, and it'll cover those costs.
spk04: Okay. This is all really helpful. I appreciate it. That's all from me. Thank you. Thank you.
spk02: This concludes our question and answer session. I would like to turn the conference back over to Andrew Ziola for any closing remarks.
spk08: All right. Thank you all. Our quiet period for the fourth quarter It 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.
spk02: The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
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