Q4 2023 EnLink Midstream LLC Earnings Call
Participants
Brian Brungardt; Director of Investor Relations; EnLink Midstream LLC
Jesse Arenivas; Chief Executive Officer, Director; EnLink Midstream LLC
Dilanka Seimon; Executive Vice President, Chief Commercial Officer; EnLink Midstream LLC
Ben Lamb; Chief Financial Officer, Executive Vice President; EnLink Midstream LLC
Spiro Dounis; Analyst; CITI
Brian Reynolds; Analyst; UBS
Zack Van Everen; Analyst; Tudor Pickering & Co.
Praneeth Satish; Analyst; Wells Fargo Securities, LLC
Christopher Jeffrey; Analyst; Mizuho Securities USA
Presentation
Operator
Greetings, and welcome to the EnLink Midstream for Q2 2023 Earnings Conference Call and Webcast.
At this time, all participants are in a listen only mode. 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 key pad. As a reminder, this conference is being recorded is now my pleasure to introduce your host released. Thank you, Brian. You may begin.
Brian Brungardt
Thank you and good morning, everyone. Welcome to Nemak's fourth quarter of 2023 earnings call. Participating on the call today are Jeff Davis, Chief Executive Officer, to walk assignments, 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 market 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 dot ilinc.com.
Today's discussion will include forward-looking statements, including expectations and predictions within the meaning of 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 to comparable GAAP measures are available in our press release in 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 dialogue and then and then the remainder of the call open for questions and answers. With that, I would now like to turn the call over to Jesse or any of us.
Jesse Arenivas
Thanks, Brian, and 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 adjusted EBITDA of $1.35 billion. This marked a solid growth of approximately 5% over the prior year. These solid results drove free cash flow after distributions of nearly $250 million for 2023.
We continue to you bust free cash flow after distributions to return capital to our investors. Earlier this year, we announced a 6% increase on our quarterly distribution. 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. Phil 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 at 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 others 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, omit 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 in Lincoln, 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 in Lincoln, ExxonMobil have agreed to reassess the Pecan Island projects near term role with the expectation that other projects may be prioritized ahead of the Pecan Island project.
Meanwhile, we continue to execute and gain expertise in energy transition and CO2 transportation space. During the fourth quarter, we achieved a milestone by bringing on line or carbon capture and transportation project at our Bridgeport facility in North Texas. Ultimately, we expect to cap you're up to 210,000 metric tons of CO2 emitted by our Bridgeport facility and deliver to a permanent sequestration site developed by our largest customer in North Texas BKV.
With that, I'll turn it over to the Loqate and provide an update on our evolving Louisiana effect.
Dilanka Seimon
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 on discuss how end length can benefit from this shifting dynamic in three phases.
In the first phase, we are focused on realizing the full value of 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 our 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 EnLink is focused on de-bottlenecking projects.
We own and operate approximately 4,000 miles of pipeline across two major interstate 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 de-bottlenecking projects, the shifting So phase of growth for and links 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 a strong customer commitments in that range.
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 solid storage capacity by an incremental nine 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 from opportunities to grow our Louisiana system and meet customer needs during this period of shifting supply and demand dynamics.
In short, this is an exciting time for endings, Louisiana system. We acquired this system over two decades ago and remain focused on optimizing the unique footprint over the next several years.
With that, I'll turn it over to Ben to provide an overview of operations and our financial results.
Ben Lamb
Thanks to Lonca and good morning, everyone. Let's start with the Permian for 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 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 approach ultimately 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. 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, EnLink delivered adjusted EBITDA of $1.35 billion and 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 at plant relocation expenses net to EnLink 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 were remain investment grade at Fitch and one notch below investment grade with 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 $0.13 in a quarter per unit in the fourth quarter, which represents a 6% rent 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 ORB. assets will be 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 2020 for guidance that we announced yesterday. We are in a solid position to continue. The momentum we ended the year with in 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 note on our core ORB. 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 contracts 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 in 2033 with annual inflation escalators and no further rate resets. When you look through these two one-time impacts, the sale of the auto RV 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 from our 2024 guidance. We assumed average WTI and Henry Hub prices of $75 per barrel 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 Waha 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 $0.5 per MMBTU impacts, adjusted 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 are projecting another year of significant growth for our Caribbean 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-2 processing facility is expected to come online in the second quarter of 2024. Louisiana 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 the longest spoke about earlier. Excluding the 2023 contribution from the RV assets that we sold, Louisiana growth will 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 from 2024 compared to 2023. However, Oklahoma 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've 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. In Oklahoma and North Texas represented over 60% of our segment profit mix today. However, the Permian in Louisiana represent approximately 60% of expected 2024.
Second profit said shortly, the largest drivers of our growth, our associated gas production in the Permian and downstream demand coal 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. So 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-2 plant relocation net to EnLink and investment contributions are forecast to be between $435 million and $485 million dollars. 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 findings optimal solution for the CCS market and the ways in which EnLink will participate in that solution. With that caveat in mind, from a free cash flow perspective, we expect a significant increase compared to 2023 was forecast cash flow after distributions in the range of $265 million to $315 million. As we disclosed in January, our Board reauthorized the $200 million a unit repurchase program for 2024 for the third consecutive year.
There is the potential to see this number cries of 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 EnLink 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 in Louisiana.
With that, I'll turn it back over to Jesse.
Jesse Arenivas
Thank you, been. In summary, I'm proud of the quick execution expanding our Louisiana assets, the bigger and broader CCS opportunity as we work with ExxonMobil and others. You addressed CO2 emitted into the atmosphere today, and there is agencies resiliency of our assets driving growth for our business in 2024 and beyond. With that, you may now open the call for questions.
Question and Answer Session
Operator
Thank you. We will now be conducting a question and answer session. You would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue, you may press star two. 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 Spiro Dounis with Citi.
Please proceed with your question.
Spiro Dounis
Thanks, operator. Community may want to start with something we're going to few questions on this morning. It really began. I would add just curious if you have some more details on what prioritization of the projects that look like. There's like Intel, you've already started spending some capital on that, that project. So curious what are some of the range of outcomes there? And when would you be able to expect to update us on that based Ferro's?
Jesse Arenivas
Jesse, I appreciate the question. First. Let me start by saying we're extremely excited about the opportunity in the expanded market. We're going to be looking for mutually beneficial opportunities with Exxon for a gain a larger share of that addressable market 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 imminently.
And this is an example of an optimization of our existing agreement to find the most cost-efficient, most timely solution for them for those initial volumes. With respect to timing, we both have obligations under the existing agreement. So we vote are highly incented to get this work through very quickly.
As from a timing perspective, we hope to update you on the path forward very soon. With respect to the capital spend, most of that those dollars were spent on permitting and 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 solution.
Spiro Dounis
That's just maybe moving on are sticking with this topic in thinking about expanding beyond that Mississippi River corridor you guys have talked about and something the order of 30 million tonnes per annum within discussion projects there. Just curious if we get an update on that.
And as you think about your competitive position beyond that corridor, I know one of the main selling point 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 the corridor.
Jesse Arenivas
Yes. I think from a return more multiple perspective, I think we 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 Gulf Coast area is our ability to execute on agreements on construction projects, operations of CO2. We are now in this phase of our North Texas assets that we've got the experience there.
I think the relationship with ExxonMobil, there's a mutually beneficial relationship. And then we are 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 another gets recognized by ExxonMobil.
Spiro Dounis
Great. No different today than it was August.
Operator
Faster question from the line of Brian rentals with UBS. Please proceed with your question.
Brian Reynolds
Hi, good morning, everyone. Maybe to touch on just the Permian growth, create cadence a little bit in a lot of M&A among some of your counterparties in the Midlands, there should be some more Delaware growth, at least out with towards forecasted them going into this year.
And then you have Matterhorn coming into service in the back half. So would be great if you could just maybe help us some break apart the Permian there and your asset base. And as we think about, you know, Permian growth cadence across our footprint for this year. Thanks.
Ben Lamb
Yes, Ryan, 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-2 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 that as a reminder, we treat that as an equity method investment in. So you're not seeing that in the guidance for segment profit for Permian, what you're seeing there and segment profit for Permian as all of our own Permian operator operations, the Matterhorn JV will hit below the line, so to speak.
Brian Reynolds
Great. Super-helpful on and maybe do a 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 hopefully you're going to capture $300 million of EBITDA as an opportunity set. Just given that were 2.5 times that, you know, are you still looking to capture kind of a 50% of market share, like, you know, could to this business ultimately makeup, not 20% of your ultimate earnings mix? Are you looking to make it even more substantial than that? Thanks.
Ben Lamb
So, you know, what we identified is really not a percentage of the market share when we talked about it just worked out that 14 was 50%. But those were identified projects that we were working with our customers and that includes ExxonMobil and beyond. Those were identified fronts, not and if you 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.
Brian Reynolds
Great. Thanks. Appreciate the color this morning.
Ben Lamb
Thanks.
Operator
Next question comes from the line of Jeremy Tonet with JPMorgan.
Please proceed with your question.
Hey, this is Noah cats on for Jamie. I was just wondering if you had any additional comments on progress with incremental CCS partners other the next time.
Brian Brungardt
You know, we continue the discussions with Shell Aloxi here. The public announcements we've made. Those are progressing as these have taken a little longer than we would have anticipated.
And I think that's for a couple of reasons. one is the uncertainties around the 45 Q. rags and then Louisiana primacy. I think a lot of those uncertainties are behind us, and we're optimistic that these things will move forward in 2024. But again, those are progressing very nicely.
Thanks. That's helpful. And a quick follow up on the contract rolls, where were the contract rolls and what do you see them rolling out into 2025?
Ben Lamb
Yes, I know it's been so these contracts were the original Devon contracts that were put in place when we formed in late way, back in 2014. And we extended in 2018 for an additional five years of term at that time, they they would have expired this year in 2024.
We pushed them out to 2029, and one of them has even been extended against an expired now in 2023. So we just agreed that at the time in 2018 that at the contracts, original expiration, SG&A rate of receptors, pre-agreed numbers. And that's what's what's happened here in the first quarter of 2024. So the rate reset preferred, it's a one-time item is not recurring and won't have a meaningful further impact in 2025.
That's helpful. Thank you, guys. Thank you.
Operator
Our next question comes from the line of Zach than ever in with Tudor, Pickering, Holt.
Please proceed with your question.
Zack Van Everen
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 crude to Sylvie. The thought process that you guys had 100% down to 25% throughout the years, that hedging gains as well?
Ben Lamb
Well phase that this has been generally. That's right. The programmatic approach that you described is our approach. I will say though, we've also gone ahead for this year, our ethane exposure because that that market is driven by many of the same forces that drive the natural gas market. In the in the prepared remarks, I mentioned a change to $5 on WT. either way moves or lose our results by about $6 million.
All else being held a healthy also is 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.
Zack Van Everen
Perfect. I 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 recent events. Can you give a percent of contracts lapse that or maybe lower rate legacy contracts that you might see additional upside and two, 25 and beyond? five of the longer?
Dilanka Seimon
You said it correct. To date, we are seeing good success in renewing existing contracts at higher rate, and most of those transactions are documented a little bit more to go and has been mentioned earlier that the opportunity to grow very, very low margin.
Zack Van Everen
Okay, perfect. Thanks, guys. Thank you.
Operator
Our next question comes from the line of Kurt reef, Satish with Wells Fargo. Please proceed with your question.
Praneeth Satish
Thanks. Good morning. I guess just going back to CCS., can you maybe elaborate on how Exxon is delineating? We're thinking about new CS. projects in the Gulf Coast between working with you guys versus Denbury. I guess what are kind of the key factors there as they think about the opportunity set hybrids as
Jesse Arenivas
Jesse? Thanks. Just I can't speak for Exxon, but broadly speaking, you've got two systems that did vary in the green line also came with additional sequestration sites. If you look on a map leak, our systems intersect that green line in multiple areas. So I think as I said earlier, we're looking for mutually beneficial opportunities. And weeks quarter happened.
We had these quicker to market happened. We get this optimized from a cost perspective, you know, return perspective. So it's a very collaborative effort. I think they're looking at this is a broader opportunity. Again, utilizing did in very assets with EnLink assets could provide unique opportunities to move forward.
Praneeth Satish
Got it. Then maybe just I guess switching gears to gas storage. Just wondering if you could kind of elaborate on the. Yes, the discussions that you're having with customers there for potential Brownsville 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 marketed?
Dilanka Seimon
Second question is a lot here. As I alluded to during the last call that a significant market interest financing S&R is driven by higher loadings commodity volatility, increasing energy exports. This requires natural gas deliveries to manage operational, no issues and increasing demand as well. So so the interest level is quite high in terms of our response to that between Osprey, natural gas storage facilities that are in operation today suggested on storage and influencer.
In general, we are looking at mix of brownfield and greenfield project and trying to optimize our Internet solution and the customer demand in that time line side, we have great cost estimate just to set and what we found out from the initial engineering studies that we have a span of all at nine Bcf from a lot even easier today.
And we can go to market rates. Having discussed, we began and as we have very attractive projects through a mixture of Broadview and some greenfield and brownfield remodel administrative up, once we get to a leverage pipeline connectivity that already exists, and then it becomes quite big versus a brand-new and get a little bit and all the infrastructure side, the combination of that would be the optimized for us.
Praneeth Satish
Got it. Thank you.
Operator
Our next question comes from the line of Christopher Jeffrey with Zuhause securities. Please proceed with your question.
Christopher Jeffrey
February. And maybe just to follow up on that last question and confirm the opportunities for the brownfield expansion will be the and are currently captured in that '24 CapEx guidance that you've given? Are you kind of looking for something less than '25 just general time line for the opportunity in the business?
Dilanka Seimon
So of in natural gas storage, gentlemen, not of the CapEx comes in to the mid of that online. So we don't have much CapEx in 2020 volumes, mainly focused on engineering studies and permitting. Some of the CapEx comes from 25 and beyond.
Christopher Jeffrey
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? Is that what's driving that?
Jesse Arenivas
You know, really a lot of our maintenance CapEx is on maintaining our compression equipment and that happens on a schedule as machines accrue hours at some point. Do you get to the point where you need to do a minor overhauls and what do you get to where you need to do a major overhaul? So it's nothing more than a heavy year for us, particularly in North Texas and Oklahoma. I'm on the scheduled maintenance.
Christopher Jeffrey
Great. Thanks, Ron.
Operator
Thank you. There are no further questions at this time. I'd like to turn the floor back over to Jesse arena for closing comments.
Jesse Arenivas
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 Italy, and we look forward to updating you with our first quarter results in May. In the meantime, we wish you well stay healthy fee and have a great day.
Operator
This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.
