EnLink Midstream, LLC

Greetings and welcome to the NLINK Midstream 4Q 2023 Earnings Conference Call-In Webcast. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brian Brungart, Director of Investor Relations. Thank you, Brian. You may begin.

Thank you, and good morning, everyone. Welcome to NLINC's fourth quarter of 2023 earnings call. Participating on the call today are Jesse Aranivas, Chief Executive Officer, Delonka Simon, Executive Vice President and Chief Commercial Officer, and Ben Lamb, Executive Vice President and Chief Financial Officer. Walter Pinto, Executive Vice President and Chief Operating Officer, is also in the room to answer any questions during the Q&A session. We issued our earnings release and presentation after the markets closed yesterday, and those materials are on our website. A replay of today's call will also be made available on our website at investors.inlink.com. Today's discussion will include forward-looking statements including expectations and predictions within the meaning of the federal securities laws. The forward-looking statements speak only as of the date of this call, and we undertake no obligation to update or revise. Actual results may differ materially from our projections, and a discussion of factors that could cause actual results to differ can be found in our press release, presentation, and SEC files. This call also includes discussions pertaining to certain non-GAAP financial measures. Definitions of these measures, as well as reconciliation of comparable GAAP measures, are available in our press release and the appendix of our presentation. We encourage you to review the cautionary statements and other disclosures made in our press release and our SEC filings, including those under the heading risk factors. We'll start today's call with a set of brief prepared remarks by Jesse, Delanca, and Ben, and then leave the remainder of the call open for questions and answers. With that, I would now like to turn the call over to Jesse Aranivas.

Thanks, Brian. Good morning, everyone. Thank you for joining us today to discuss our fourth quarter results and full 2023 results. We'll also discuss our 2024 outlook, which looks like it will be another great year driven by solid business activity. Looking back at 23, I'm proud of the team's strong execution, driving a number of records despite the challenging and volatile commodity environment. Last night, we reported fourth quarter adjusted EBITDA of $351 million and 2023 adjusted EBITDA of $1.35 billion. This marked solid growth of approximately 5% over the prior year. These solid results drove free cash flow after distributions of nearly $250 million for 2020-2023. We continue to use our robust free cash flow after distributions to return capital to our investors. Earlier this year, we announced a 6% increase on our quarterly distributions. Additionally, we fully executed our expanded $250 million common unit repurchase program. Since we began our consistent unit repurchase program in late 2021, we have repurchased approximately 9% of the common units outstanding. Ben will provide more details later in the call, but we forecast this momentum to continue into 2024. Growth this year will be led by our largest business the Permian, followed by Louisiana, which we expect to become our second largest segment this year. The growth in those businesses will be partly offset by the impact from the non-core ORV asset sale in late 2023 and a contractual rate reset in certain legacy Oklahoma and North Texas commercial agreements. Overall, we forecast adjusted EBITDA of $1.36 billion at the midpoint of our guidance range. The continued strong cash flow generation, coupled with lower total capital expenditures, will drive significant increase in free cash flow after distributions to $290 million at the midpoint of our guidance. Earlier this year, we announced that the board authorized another $200 million common unit repurchase program for 2024, which represents a third consecutive year of at least $200 million of repurchases. Last night we released an update around our CO2 transportation solution for ExxonMobil. Following ExxonMobil's recent acquisition of Denbury, we expanded our commercial discussions to provide safe, reliable, and cost-efficient CO2 transportation to other areas across the Gulf Coast beyond the Mississippi River Corridor. In total, The industrial facilities along the Gulf Coast between Houston and New Orleans emit over 215 million metric tons of CO2 today into the atmosphere. We're excited for this opportunity to expand our commercialization efforts with Exxon, as it may represent a larger investment opportunity and an expanded reach into multiple markets. InLink and ExxonMobil continue to work closely together on CO2 transportation solutions since our initial agreement in 2022, and look forward to continuing our collaboration to help reduce carbon emissions across the Gulf Coast. In connection with the expanded evaluation, while the original transportation agreement remains in place, InLink and ExxonMobil have agreed to reassess the Pecan Island project's near-term role, with the expectation that other projects may be prioritized ahead of the Pecan Island project. Meanwhile, Enly continues to execute and gain expertise in energy transition and CO2 transportation space. During the fourth quarter, we achieved a milestone by bringing online our carbon capture and transportation project at our Bridgeport facility in North Texas. Ultimately, we expect to capture up to 210,000 metric tons of CO2 emitted by our Bridgeport facility and deliver it to a permanent sequestration site developed by our largest customer in North Texas, BKV. With that, I will turn it over to Nalanka to provide an update on our evolving Louisiana SEC.

Thanks, Jesse, and good morning, everyone. Last quarter, we discussed how the Louisiana gas supply and demand market dynamics have shifted over the past year. While we continue to evaluate opportunities, I wanted to spend this time to provide an update and discuss how NLINC can benefit from this shifting dynamic in three phases. In the first phase, we are focused on realizing the full value of our assets and we stand to benefit from renewing current business at higher rates and often for longer terms. We began to see the benefit in the second half of 2023 and we expect this to continue. As contracts expire and are renewed, we estimate the value of the higher rates in 2024 is approximately $20 million and we see further upside in 2025 and beyond. The second phase of growth for NLINK is focused on de-bottlenecking projects. We own and operate approximately 4,000 miles of pipeline across two major intrastate systems, as well as the Henry Hub. And we connect to over a dozen third-party systems offering customers significant connectivity, particularly in the southern part of Louisiana. These projects are relatively quick to execute, generally less than 18 months, and provide very attractive economics, typically low single-digit EBITDA multiples. Examples include adding compression or looping short distances of existing pipelines. Beyond quick, efficient debulldecking projects, the shifting supply and demand dynamics create a potential third phase of growth for Enlink's Louisiana system. As LNG export capacity comes online over the next several years in Louisiana and with emerging industrial demand such as blue ammonia projects, we expect the forces impacting the markets today will only grow stronger. The rising demand for natural gas to serve this growing market may drive the need for larger projects such as new pipelines and expansions of natural gas storage to support our customers. While we are focused on meeting the needs of customers in this new environment, we remain committed to capital-efficient projects that are underwritten by strong customer commitments. In that vein, we have been evaluating opportunities to expand our natural gas storage portfolio. We currently have working natural gas storage capacity of about 11 BCF. Since the last earnings call when we mentioned this, We have progressed engineering studies and estimate that we can expand our salt storage capacity by an incremental 9 BCF and are currently marketing this capacity. We will continue to provide updates on these exciting projects in the coming quarters, but this is the latest example of longer-term opportunities to grow our Louisiana system and meet our customer needs during this period of shifting supply and demand dynamics. In short, this is an exciting time for EndLink's Louisiana system. We acquired this system over two decades ago and remain focused on optimizing this unique footprint over the next several years. With that, I'll turn it over to Ben to provide an overview of our operations and our financial results.

Thanks, Dilanka, and good morning, everyone. Let's start with the Permian. where segment profit for the fourth quarter of 2023 came in at $105.9 million, including approximately $9.6 million of gross operating expenses tied to plant relocations and $4 million of unrealized derivative gains. Excluding plant relocation OPEX and unrealized derivative activity, segment profit in the fourth quarter of 2023 decreased 1% sequentially, but grew 11% from the prior year quarter. Producer activity behind our systems remained robust, driving a record quarter for gathered volumes, with average natural gas gathering volumes approximately 6% higher sequentially and 23% higher than the prior year quarter. Turning now to Louisiana, we experienced another quarter of solid performance in the gas segment, along with strong results in the NGL segment that benefited from normal seasonality. Segment profit for the fourth quarter of 2023 came in at $103.6 million, including $0.9 million of unrealized derivative gains. Excluding the impact of unrealized derivative activity, segment profit in the fourth quarter of 2023 grew approximately 10% sequentially and grew approximately 2% compared to the prior year quarter. During the fourth quarter, we fully exited our non-core Ohio River Valley assets for total proceeds of approximately $70 million. This represents a multiple of approximately six times EBITDA. Moving up to Oklahoma, we delivered segment profit of $112 million for the fourth quarter of 2023, including $1.3 million of unrealized derivative gains. Excluding unrealized derivative activity, segment profit in the fourth quarter of 2023 grew approximately 1% sequentially and grew approximately 7% from the prior year quarter. During the fourth quarter, we continued to be impressed with the resilience of our business as we saw operators remain active with rigs on our acreage, driving gathering volumes flat sequentially and approximately 15% higher compared to the prior year quarter. Wrapping up with North Texas, segment profit for the quarter was $68.6 million, including $0.7 million of unrealized derivative gains. Excluding unrealized derivative activity, Segment profit in the fourth quarter of 2023 decreased approximately 2% sequentially and decreased approximately 10% from the prior year quarter. Natural gas gathering volumes were 1% lower sequentially and 9% lower compared to the prior year quarter. These solid results were in line with our expectations and drove another robust quarter with $350.8 million in adjusted EBITDA and $79.4 million in free cash flow after distributions. For the full year 2023, NLINC delivered adjusted EBITDA of $1.35 billion in free cash flow after distributions of $247 million. This represents 5% growth in adjusted EBITDA over the prior year, reflecting the resilience of our diverse asset base despite the volatile commodity price environment. Capital expenditures, plant relocation expenses, net to NLINC, and investment contributions were $122 million in the fourth quarter of 2023. On the balance sheet side, we continue to be in a very strong position with a leverage ratio of 3.3 times at the end of the fourth quarter, and we retain ample liquidity. We remain investment grade at Fitch and one notch below investment grade at both S&P and Moody's with a positive outlook at S&P. Consistent with our capital allocation plan to return capital to investors, we increased our quarterly common unit distribution to 13.25 cents per unit in the fourth quarter, which represents a 6% increase over the fourth quarter of 2022. During the fourth quarter, the Board increased our 2023 common unit repurchase authorization to $250 million. The increase reflected our strong free cash flow generation, as well as a portion of the proceeds from our sale of our non-core ORV assets. We fully executed the expanded authorization, including GIP's pro-rata share, which settled after the end of the quarter. Following our consistent approach to repurchase common units beginning in late 2021, we have now repurchased nearly 42 million common units, representing approximately 9% of the common units outstanding at the beginning of our repurchase activity. Now let me turn to the 2024 guidance that we announced yesterday. We are in a solid position to continue the momentum we ended the year with, and 2024 is forecast to be another year of solid results. From an adjusted EBITDA standpoint, we are forecasting a range of $1.31 billion to $1.41 billion. This outlook reflects solid growth in our two largest segments, the Permian and Louisiana, while partially offset by the impact from the non-core ORV asset sale in late 2023 and contractual rate resets in certain legacy North Texas and Oklahoma commercial agreements. These contracts were extended back in 2018. and the agreement included a one-time rate reset in 2024, the contract's original expiration date, to pre-agreed fees. In effect, this reset partially reverses recent years of outsized annual inflation escalators. These contracts now expire between 2029 and 2033 with annual inflation escalators and no further rate resets. When you look through these two one-time impacts, the sale of the ORV assets and the one-time contract resets, Our base business is forecast to grow approximately 4% at the midpoint of adjusted EBITDA guidance compared to 2023. Turning now to commodity prices, we remain approximately 90% fee-based. For our 2024 guidance, we assumed average WTI and Henry Hub prices of $75 per barrel and $3 per MMBTU, respectively. Like last year, we took the opportunity in the second half of 2023 to take advantage of the supportive forward curve and hedged a large majority of our 2024 exposure to natural gas prices and WHAA basis at prices significantly above current levels, providing increased visibility for 2024 financial results. Accordingly, a scenario of plus or minus $5 per barrel and 50 cents per MMBTU impact suggested EBITDA by approximately $6 million and $5 million, respectively, assuming no change in our forecast volumes. Taking guidance down to the segment level and focusing on the midpoints of the ranges we provided, we're projecting another year of significant growth for our Permian business with segment profit for 2024 forecast to be $455 million, including plant relocation expenses, representing an increase of approximately 15%. As a reminder, our Tiger II processing facility is expected to come online in the second quarter of 2024. Louisiana's segment profit for 2024 is forecast to be $420 million, representing an increase of approximately 7%. The increase is mainly driven by the improving fundamentals in our natural gas business that Delonka spoke about earlier. Excluding the 2023 contribution from the ORV assets that we sold, Louisiana growth would be even higher. In Oklahoma, we expect the activity from the Devon Dow JV, along with a little activity from other customers, will keep volumes approximately flat in 2024 compared to 2023. However, Oklahoma's segment profit for 2024 is forecast to be $390 million, representing a decline of approximately 8%, driven in part by the one-time rate reset that I talked about earlier. Finally, North Texas segment profit for 2024 is forecast to be $240 million, representing a decline of approximately 13%. This is driven by the one-time rate reset, but also reflects a conservative view on volumes given the current gas price environment. The growth in our business the last several years has been impressive, and our 2024 outlook reflects a transformation of our business. Back in 2019, Oklahoma and North Texas represented over 60% of our segment profit mix. Today, however, the Permian and Louisiana represent approximately 60% of expected 2024 segment profit. Said shortly, the largest drivers of our growth are associated gas production in the Permian and downstream demand pull markets in Louisiana. While our guidance is based on the most current producer drilling plans, we recognize the extreme volatility in natural gas prices may cause producers to delay their drilling and completion plans and thereby impact our volume expectations. We estimate a hypothetical six-month completion deferral by major customers in Oklahoma and North Texas, both gas-oriented basins, would have an aggregate 2024 impact of approximately $20 million. As we've said before, though, Longer term, we remain very bullish on natural gas demand and the need for Oklahoma and North Texas to help supply that growing market in the coming years. On the investment front, total capital expenditures plus operating expenses associated with the Tiger II plant relocation, net to in-link, and investment contributions are forecast to be between $435 million and $485 million. As we have previously discussed, we remain focused on capital efficient, high return projects. I want to point out that our capital spending outlook includes approximately $50 million of spending for CCS projects with ExxonMobil. As Jesse described in his opening remarks, this number may change as we and Exxon work toward finding the optimal solution for the CCS market and the ways in which NLINK will participate in that solution. With that caveat in mind, from the free cash flow perspective, we expect a significant increase compared to 2023, with forecast free cash flow after distributions in the range of $265 million to $315 million. As we disclosed in January, our board reauthorized the $200 million common unit repurchase program for 2024 for the third consecutive year. There is the potential to see this number rise as the year goes on, as it did last year, as we gain more clarity on some of the moving pieces, including Exxon-related CCS projects. In summary, the NLINC team delivered solid results in 2023, and we expect the momentum to continue in 2024. Despite the recent volatility, our assets are well-positioned to grow, led by our two largest segments, the Permian and Louisiana. With that, I'll turn it back over to Jesse. Thank you, Ben. I'm proud of the quick execution expanding our Louisiana assets, the bigger and broader CCS opportunity as we work with Exxon Mobil and others to address CO2 emitted in the atmosphere today, and the resiliency of our assets driving growth for our business in 2024 and beyond. With that, you may now open the call for questions.

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we poll for questions. Thank you. Our first question comes from the line of Spirodonis with Citi. Please proceed with your question.

Thanks, Operator. Morning, Citi. I may want to start with something we're getting a few questions on this morning related to Pecan Islands. Just curious if you can give us some more details on what prioritization of other projects could look like there. As far as I can tell, You've already started spending some capital on that project. So I'm curious, what are some of the range of outcomes there, and when would you be able to expect to update us on that?

Hey, Spiro, it's Jesse. I appreciate the question. First, let me start by saying, you know, we're extremely excited about the opportunity in the expanded market. We're going to be looking for mutually beneficial opportunities with Exxon for years. you know, to gain a larger share of that addressable market, you know, expanding outside of the Mississippi River corridor. What that entails is we've identified, as we've said in the past, right, we believe that the Denbury acquisition leads to more opportunities for in-link. And this is an example of an optimization of our existing agreement to find the most cost-efficient most timely solution for those initial volumes. With respect to timing, we both have obligations under the existing agreement. So we both are highly incented to get this work through very quickly. So from a timing perspective, we hope to update you on the path forward very soon. With respect to the capital spend, most of those dollars were spent on permitting right-of-way acquisition. We have taken a step back as we reassess, and so we will not be incurring future spending until we identify the most optimized solutions.

Okay, understood. Thanks for that. Jesse, maybe moving on or sticking with this topic and thinking about expanding beyond that Mississippi River corridor. You know, I know you guys have talked about, I think, something in the order of 30 million tons per annum within discussion projects there. Just curious if we can get an update on that. And as you think about your competitive position beyond that corridor, I know one of the main selling points here was a lot of brownfield assets in the ground that you can repurpose. As you expand beyond, I don't think you've got as much of that. So curious how you're thinking about some of the return multiples outside that corridor.

Yeah, I think from a return multiple perspective, I think you would expect those to compete with our traditional midstream business. So those multiples will have to be competitive. I think where we have a competitive advantage, again, is our decades-long experience, both in Louisiana and as we expand into Texas, the Gulf Coast area. is our ability to execute on agreements, on construction projects, operations of CO2 pipes. We are now in the phase of our North Texas asset, so we've got the experience there. I think the relationship with ExxonMobil, there is a mutually beneficial relationship in that we are a pipeline infrastructure company as we set out to be the Transporter of choice, that is materializing. And the value add there is going to be timely execution, experience, customer relationships. So I think we do have a value add, and I think it's recognized by ExxonMobil.

Great. I'll leave it there for today. Thanks for the time, guys.

Thanks, Bill.

Thank you. Our next question comes from the line of Brian Reynolds with UBS. Please proceed with your question.

Hi, good morning, everyone. Maybe to touch on just the Permian growth create cadence a little bit, you know, a lot of M&A amongst some of your counterparties in the Midlands. You know, there should be some more Delaware growth, at least that's where it's forecasted going into this year. And then you have Matterhorn coming into service in the back half. So it would be great if you could just maybe help us, you know, break apart the Permian there and your asset base as we think about, you know, Permian growth cadence across your footprint for this year. Thanks.

Yeah, hey, Brian, this is Ben. Look, you're right there in your commentary. If you look at the driver of our Permian growth for 2023, it was largely in the Midland gas segment. This year, we expect to see more of it come from the Delaware gas side with the Tiger II plant coming into service just in time in the second quarter of this year. In terms of Matterhorn, it will be in service in the third quarter. But as a reminder, we treat that as an equity method investment. And so you're not seeing that in the guidance for segment profit for Permian. What you're seeing there in segment profit for Permian is all of our own Permian operations. The Matterhorn JV will hit below the line, so to speak.

Great, super helpful. And maybe to follow up on some of the CCUS questions, I believe last quarter you kind of talked about an 80% MCPA market opportunity in Louisiana, which, you know, hopefully you're going to capture, you know, 300 million of EBITDA as an opportunity set. You know, just given that we're two and a half times that, you know, are you still looking to capture kind of 50% of market share? Like, you know, could this business ultimately make up, you know, not 20% of your ultimate earnings mix? Are you looking to make it, you know, even more substantial than that? Thanks.

So, you know, what we identified was really not a percentage of the market share when we talked about, it just worked out that 40 was 50%, but those were identified projects that we were working with our customers, and that includes ExxonMobil and beyond. Those were identified projects, not to put a marker out there on a percent of the total addressable market, but certainly now that we have expanded into multiple geographic regions, and a much larger addressable market, we do anticipate and are optimistic that this business gets bigger than the initial $300 million business that we identified earlier.

Great. Thanks. I appreciate the cover this morning. Thanks.

Thank you. Our next question comes from the line of Jeremy Tonant with JP Morgan. Please proceed with your question.

Hey, this is Noah Katz on for Jeremy. I was just wondering if you had any additional comments on progress with incremental CCS partners other than Exxon?

You know, we continue the discussions with Shell, Oxy, you know, the public announcements we've made. Those are progressing. I think these have taken a little longer than we would have anticipated. But I think that's for a couple reasons. One is the uncertainties around the 45Q regs and then, you know, Louisiana primacy. I think a lot of those uncertainties are behind us, and we're optimistic that, you know, these things will move forward in 2024. But again, those are progressing very nicely.

Thanks. That's helpful. And as a quick follow-up on the contract rules, where were the contract rules, and what do you see them rolling at into 2025?

Yeah, hey, Noah, it's Ben. So these contracts were the original Devon contracts that were put in place when we formed DENLink way back in 2014. And we extended them in 2018 for an additional five years of term. At that time, they would have expired this year in 2024. We pushed them out to 2029. And one of them has even been extended again since then. And it expires now in 2023. So we just agreed back at the time in 2018 that at the contract's original expiration date, the rates would reset to pre-agreed numbers. And that's what's happened here in the first quarter of 2024. So the rate reset has occurred. It's a one-time item. It's not recurring and won't have a meaningful further impact in 2025. That's helpful.

Thank you, guys.

Thank you. Our next question comes from the line of Zach Van Everen with Tudor Pickering Holt. Please proceed with your question.

Hey, guys. Thanks for taking the question. Just one on hedging. It sounds like you're pretty well protected on the natural gas side. Flipping to NGLs and crude, should it still be the thought process that you guys hedge 100% down to 25% throughout the year, or is that hedging changed as well?

Hey, Jack, this is Ben. Generally, that's right. The programmatic approach that you described is our approach. I will say, though, we've also gotten ahead for this year on our ethane exposure because that market is driven by many of the same forces that drive the natural gas market. In the prepared remarks, I mentioned that a change of $5 on WTI either way moves our result by about $6 million, all else being held equal. So it's not a huge driver, frankly, either way. Of course, the bigger impact is on producer activity, and we gave you some guidance around that as well.

Perfect. Appreciate that. And then the last one is just on the contracts that are rolling off in Louisiana. It seems like you guys are seeing pretty good upside from the rate resets. Can you give a percent of contracts left that are maybe lower rate legacy contracts that you might see additional upside in 25 and beyond?

It's Delonco, and you stated correctly, you know, we are seeing good success in renewing the existing contracts at higher rates. And most of those transactions are done, but a little bit more to go. And as Ben mentioned earlier, we've baked that uplift into our 2024 budget. Okay.

Perfect. Thanks, guys.

Thank you. Our next question comes from the line of with Wells Fargo. Please proceed with your question.

Thanks. Good morning. I guess just going back to CCS, can you maybe elaborate on how Exxon is delineating or thinking about new CCS projects in the Gulf Coast between Working with you guys versus Denberry, I guess what are kind of the key factors there as they think about the opportunity set?

Hi, Brent. It's Jesse. Thanks. I think just I can't speak for Exxon, but broadly speaking, you've got two systems. The acquisition of Denberry and the Green Line also came with additional sequestration sites. If you look on a map, you know, in Link, our systems intersect that green line in multiple areas. So I think, as I said earlier, we're looking for mutually beneficial opportunities to gain more market share, right? So that's going to be how can we do this quicker? How can we get these quicker to market? How can we get this optimized from a, you know, cost perspective, you know, return perspective? So it's a very collaborative effort. I think they're looking at this as a broader opportunity you know, again, utilizing the InBerry assets with the InLink assets could provide unique opportunities to move forward.

Got it. And then maybe just, I guess, switching gears to gas storage, just wondering if you could kind of elaborate on the discussions that you're having with customers there for potential brownfield storage expansion in Louisiana. Do you think the current market rate is high enough to support three- to five-year contracts on that expansion? Maybe if you could just kind of ballpark what the cost of that expansion would be. And then finally, is there a scenario where you take some of this capacity yourself and market it?

Thanks for the question. It's Delon here. As I had alluded to during the last call, there is significant market interest for natural gas storage driven by multiple things, commodity volatility, increasing LNG exports, which requires natural gas storage to manage operational issues, and increasing demand as well. So the interest level is quite high. In terms of our response to that, between our three natural gas storage facilities that are in operation today, Jefferson Island Storage, Napoleonville, and Sorrento, we are looking at a mix of brownfield and greenfield projects and trying to optimize what is the best solution and to meet the customer demands in that timeline. So I don't have great cost estimates. Just a second. What we've found out from the initial engineering studies is that we can expand this about at 9 BCF from about 11 BCF today. And we think at the market rates, that are being discussed, we can definitely have very attractive projects through a mixture of brownfield and some greenfield. The brownfield one of the benefits, of course, we get to leverage pipeline connectivity that already exists, and that becomes quite significant versus a brand-new development of all the infrastructure. So a combination of that would be the optimized solution for us.

Got it. Thank you.

Thank you. Our next question comes from the line of Christopher Jeffrey with Mizuho Securities. Please proceed with your question.

Hi, everyone. Maybe just to follow up on that last question and confirm, if the – opportunities for the brownfield expansion in Louisiana are currently captured in that 24 capex guide that you've given, or are you kind of looking for some of that in 25, or just general timelines of the opportunity and the phases?

Sure. In natural gas storage development, a lot of the capex comes in a little bit towards the mid of that timeline, so we don't have much capex in 2024. It's mainly focused on engineering studies and permitting. Some of the CapEx comes in 25 and beyond.

Got it. And then maybe just another looking at the maintenance CapEx for the 24 guide. It looks like a decent step up from 23. Any color there as to what's driving that?

Yeah, you know, really a lot of our maintenance CapEx is on maintaining our compression equipments. And that happens on a schedule. As machines accrue hours, at some point you get to the point where you need to do a minor overhaul, and at some point you get to where you need to do a major overhaul. So it's nothing more than a heavier year, particularly in North Texas and Oklahoma, on scheduled maintenance.

Great. Thanks a lot.

Thank you. There are no further questions at this time. I'd like to turn the floor back over to Jesse Arenas for closing comments.

Thank you, Alyssa, for facilitating our call this morning, and thank everyone for being on the call today and for your support. As always, we appreciate your continued interest and investment in Inley, and we look forward to updating you with our first quarter results in May. In the meantime, we wish you well, stay healthy, and have a great day.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.