Kinder Morgan, Inc. (KMI) Q3 2024 Earnings Report, Transcript and Summary

Welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions] Today's call is being recorded. If you have any objections, please disconnect at this time. I will now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Okay. Thank you, Ted. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, and the Securities and Exchange Act of 1934, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. Over the past few quarters, I've talked about our view of the future demand for natural gas with strong growth being driven by LNG exports, exports to Mexico, and electric generation which is benefiting from the tremendous needs of AI and data centers. Our viewpoint is consistent with most other energy leaders and analysts in the field. So, the next question is, what's the impact of this growth on a midstream company like Kinder Morgan? We believe it's substantial and positive. In fact, in my decades of experience in the mid-term arena, I've never seen a macro environment so rich with opportunities for incremental build-out of natural gas infrastructure. And at Kinder Morgan, we expect to be a major player in developing that infrastructure. In July, we announced the approximate $3 billion South System Expansion 4 Project, which is underpinned by long-term shipper commitments and designed to increase our Southern Natural Gas South Line capacity by approximately 1.2 Bcf per day, helping to meet growing power generation and residential commercial demand in the Southeastern US market. Today, we are announcing the expansion of our GCX system in Texas, which will enable our customers who have signed long-term throughput agreements to move substantial additional gas out of the Permian Basin. We expect to announce additional significant projects over the next several months that will allow us to expand and extend our network to better serve the needs of our customers and benefit our bottom-line. As these projects come online, we should be able to grow our EPS, EBITDA, and DCF on a consistent and sustainable basis for years to come. And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. I'll make a few points and then I'll turn it over to Tom and David to give you more details. But for the third quarter, earnings per share was unchanged. EBITDA grew by 2% versus the third quarter of last year. For the year, we expect EBITDA growth of 5% and EPS growth of 9% versus 2023, despite our expectation to be slightly below our budget due to lower commodity prices and slow start-up of our RNG facilities. Debt-to-EBITDA remains at 4.1 times. During the quarter, we added roughly $450 million of projects to the backlog, which includes the GCX expansion that Rich mentioned, but also includes a storage expansion on NGPL and a new lateral to serve a natural gas power plant. We placed roughly $500 million of projects in service resulting in a current backlog of $5.1 billion. As we look to the future, we continue to see large opportunities for growth in natural gas between LNG, exports to Mexico, power, and industrial growth. Current discussions on power opportunities total well north of the 5 Bcf a day we mentioned in the second quarter. Our internal number for growth in the overall natural gas market is roughly 25 Bcf a day over the next five years. On the power side, there are numerous drivers of that demand. We see population and business migration to the Southern United States from Arizona to Texas to Georgia and Florida in what were already tight energy markets. The CHIPS Act, cheap feedstock prices, and national security are leading to onshoring and nearshoring. Renewables are leading to the need for more natural gas peaker plants to back up intermittent demand. Coal plants are moving forward with conversion and of course, data center demand has skyrocketed. Regardless of the demand driver, one project often creates a need for a subsequent project. For example, an LNG facility initially builds or contracts for a header pipe to get natural gas to its facility from the closest liquid market. Over time, it contracts for capacity upstream of that liquid point to secure more attractively priced molecules. In addition, we have seen some of these companies subscribe for capacity on an entirely separate path to achieve diversity of supply. We see somewhat similar dynamics on the LDC and power demand side, projects to expand existing pipeline capacity within the demand areas and then a desire to reach further back to ensure sufficient and diverse supply. It kind of reminds me of the old song by the Fixx, One Thing Leads to Another. As we look at our future opportunity set, a few of the potential projects are very large, $1.5 billion to $2 billion. Most are singles and doubles. As I said last quarter, not all the projects will come to fruition and the larger projects can take longer to develop, but the opportunity set has continued to increase over the course of this year and the conversations are becoming more focused and specific. As Rich mentioned, we've already approved two large projects totaling $3.6 billion A Rate, $1.8 billion to KM-share between Southern Natural Gas -- the Southern Natural Gas South System 4 Project and the GCX expansion. And I expect, as Rich said, we'll continue to add to this backlog. It's an exciting time to be in the midstream business. And with that, I'll turn it over to Tom to give you more details.

Thanks, Kim. Starting with the natural gas business unit, transport volumes increased 2% in the quarter versus the third quarter of 2023. Natural gas gathering volumes were up 5% in the quarter compared to 2023, driven by Haynesville and Eagle Ford volumes, which were up 10% and 9% respectively. Sequentially, total gathering volumes were down 5%. For the year, we expect gathering volumes to average 8% below our 2024 plan but 5% over 2023. We view the slight pullback in gathering volumes as temporary as higher production volumes will be necessary to meet the demand growth from LNG expected in the second-half of 2025. Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation and storage capabilities in support of the growing natural gas market. In our Products Pipeline segment, Refined Products volumes were up 1%, and Crude and Condensate volumes were down 4% in the quarter compared to the third quarter of 2023. For the full-year, we expect Refined Products volumes to be slightly below our plan at 2% over 2023. Regarding development opportunities, KMI's SFPP pipeline closed a successful binding open season during the quarter to add 2,400 barrels per day of additional refined petroleum products capacity on its Eastline system for transportation services from El Paso, Texas to Tucson, Arizona. The project can be expanded further and is expected to be in service during the third quarter of 2025. In our Terminals business segment, our liquids lease capacity remains high at 95%. Refining cracks and blending margins, though down from recent highs remain constructive and supportive of strong rates and high utilization at our key hubs in the Houston Ship Channel in New York Harbor. Our Jones Act tankers are 100% leased through 2024 and 97% leased in 2025, assuming likely options are exercised. The current market rates remain above our fleet average charter rate and we expect to re-contract at higher charter rates as contracts come up for renewal. The CO2 segment experienced lower oil production volumes at 6%, lower NGL volumes at 3%, and higher CO2 volumes at 3% in the quarter versus the third quarter of 2023. For the full year, we expect oil volumes to be roughly flat to budget. The Board approved two projects today associated with our acquisitions over the last couple of years. These projects include the development of a CO2 flood at the undeveloped leasehold adjacent to SACROC that we acquired in June and the second Phase of the CO2 flood development at Diamond M. We expand -- expect to spend a combined $145 million on these projects, resulting in a peak oil production of greater than 5,000 barrels a day. With that, I'll turn it over to David Michels.

Thanks, Tom. So, for the quarter, we're declaring a dividend of $0.2875 per share, which is $1.15 annualized, up 2% from our 2023 dividend. For the quarter, we generated revenue of $3.7 billion, down $208 million from the third quarter of 2023. However, cost of sales were also down and those were down by $381 million. And so, putting those two together, gross margin increased 7% versus last year. Additionally, we generated net income attributable to KMI of $625 million and earnings per share of $0.28, both 17% higher than the third quarter of 2023. On an adjusted net income basis, which excludes certain items, we generated $557 million and adjusted EPS of $0.25, which is flat with last year. We saw year-over-year growth from our natural gas and terminals businesses. The main drivers were contributions from our acquired South Texas midstream assets, greater contributions from our natural gas transportation and storage services across our networks, as well as higher-growth project contributions. Our Products segment was down mainly due to lower commodity prices and the associated impact on our inventory valuations. DCF per share was $0.49, flat with last year. We experienced higher sustaining capital versus last year in the quarter, which is consistent with how we budgeted for it. For the full year, we expect sustaining capital to be in line with budget. So, the quarter was pretty flat with last year. But if you look at a year-to-date -- on a year-to-date basis, performance is nicely up. EPS is up 9% over last year and our adjusted EPS is up 5% on a year-to-date basis versus last year. And as Kim mentioned, while we expect to trend a little bit below budget for the full year, we expect our full year adjusted EBITDA to be 5% higher than 2023 and our adjusted EPS to be 9% higher than 2023. On our balance sheet, we ended the third quarter with $31.7 billion of net debt and 4.1 times net debt to adjusted EBITDA, which is consistent with where we budgeted to end the quarter. Our net debt has decreased $150 million from the beginning of the year and here is a high-level reconciliation of how that change occurred. We've generated $4.2 billion of cash flow from operations. We spent $1.9 billion in dividends. We've spent $2 billion in total CapEx that includes growth, sustaining, and our contributions to our joint ventures. And we've had $50 million approximately of other working capital uses and that gets you close to the $150 million decrease in net debt for the year. And now, I'll turn it back to Kim.

Okay. Thanks, David. Ted, if you'll come back on, we'll open it up to questions.

The phone lines are now open for questions. [Operator Instructions] The first question in the queue is from John Mackay with Goldman Sachs. Your line is open.

Hey, everyone. Thank you for the time. Look, you spent a lot of time again talking about the growth potential that you're seeing coming back across power, et cetera. You've -- you have a couple of projects that are floating around kind of not quite in the backlog yet. I guess we used to call it shadow backlog. I guess I'd just be curious if you could kind of frame up the size of that relative to, let's say, this time last year. And then if you could maybe touch on in that context, maybe Mississippi Crossing and Trident, that'd be great.

Sure. I mean, I think, as I said earlier, the opportunity set has continued to increase versus from the start of this year and even more since this time last year. And so, I mean, we don't technically have a shadow backlog, but if we did, I would expect that you would see a big increase in that. And so, those projects arrange a lot of singles and doubles, which are great. I think those projects have less risk, and they are generally built off of our existing network and they're very nice returns. And then we have some, that could be much larger. But if you look at, for example the power opportunity, we are talking to power plants in Arizona and Arkansas and Texas and Mississippi and Louisiana and Wisconsin and Colorado. And then obviously, we're addressing the Georgia need through the South System 4. The things that you're seeing on the industrial side, you're seeing battery plants and chip plants in Arizona. You're seeing auto plants in Georgia, petrochemical plants on the U.S. that's driven by the onshoring, that's driven by the CHIPS Act, and that's driven by the fact that we've just got very cheap commodity prices here. So, cheap feedstock for these petrochemical plants. On the export to Mexico, that's driven by power plants, that's driven by nearshoring, that's driven by export LNG. We've got CCS opportunities on petroleum products side. We've -- I got a number of blending opportunities we're working on. There's opportunities on the storage side. As I said today, we -- NGPL added a 10 Bcf storage, opportunity, we added our share of that to the backlog. And so -- and then, on natural gas. So, our backlog itself has grown significantly from last year. I don't remember the exact number, but I think it was in the $3 billion or below this time last year. And now we're over $5 billion. So, that gives you some sense of the things that we're seeing. Also since this time last year, we were saying $1 billion to $2 billion a year in expansion CapEx, and we updated that more recently to say $2 billion in expansion CapEx per year. So, those are all signs of how we see this opportunity set. On the MSX project, I'll let Sital talk about that, the open season.

Yes, John, this is Sital. So, as you -- as we've been talking about the last couple of calls, we've got two open seasons out there, our theme. We've been saying for a while that we've got a need for more molecules to move from West to East. So, what you have is two open seasons, one with Mississippi Crossing and one with Trident. That basically is getting molecules to where they're needed. Mississippi Crossing can be scaled up to 2 Bcf to get to this -- to the Southeast markets, obviously, to feed some of the Southeast customers that we're working with on South System 4. Trident is a project that gets gas from Katy all the way to the LNG corridor in Port Arthur. And so, we're excited about those projects. We're working with our customers. Needless to say, both of them are in kind of a competitive space. So, hopefully, we'll have more to share on the next call as it pertains to those.

And they just gave me the number on the backlog, third quarter last year was $3.8 billion. So, we've gone from $3.8 billion to $5.1 billion. So, that's a 34% increase in the backlog.

All right. That's great color. Appreciate all that. I think just second question, we're going into guidance two months from now, obviously, not going to ask you on specific numbers or anything, but if we look at where '24 has trended versus initial guidance, big part of that has been commodity softness. We can debate over how much of that is transitory or not. But could you talk about maybe other puts and takes inside the business that are trending better or slightly softer than expected outside of commodity and just maybe generally how some of those can -- how they'll trend into '25?

Sure. So, on the natural gas side, obviously got the commodity impact and that's impacting gathering volumes. And so we've seen some weakness versus our budget. And you heard Tom address that in his comments on gathering volumes. On the other hand, we have seen huge strength in the transmission assets, and that's on transport contracts, that's on storage, that's on PAL. And so a lot of upside versus our original budget there, that's offsetting the downside -- some of the downside that we see on commodity and the G&P volumes. So, I think, the question, when you start looking into 2025 is going to be around what we expect G&P volumes to be. I think it's kind of too early to talk about that. I think the first half of the year probably looks a lot like 2024. I think as some of these export LNG volumes come on in the back half, whether that's, I think Corpus has got some volumes coming on. I think Golden Pass should at the end of the year. And then, I think there is some in [Indiscernible]. So, I think, with those volumes coming on, that will lead to a stronger environment to some extent on -- and part of that also depends on what kind of winter we have. But I think going into '25, on the other business segments and, say, products and terminals have rate escalators, we've got some upside on Jones Act. Interest rates are obviously going to be a benefit to us. Expansion projects, getting our RNG facility stabilized, and then we'll just have to see where G&P comes out and where we come out on commodity prices. And then I think cash taxes will probably go up a little bit, but we still will not be a overly significant cash taxpayer.

All right. That's fantastic. I appreciate the time.

The next question in the queue is from Michael Blum with Wells Fargo. Your line is open.

Thanks. Good afternoon, everybody. I wanted to just stay on the topic of the percolating gas, gas demand, gas projects. Given just the growing potential backlog of projects that you're looking at, where do you see CapEx trending over the next few years? I know you last quarter kind of raised it from $1 billion to $2 billion up to $2 billion plus or minus $1 billion of growth CapEx, but do you see that trending even higher over time? And any idea of where that could go?

Okay. So, Michael, I'd say it could. I'd say at this point, there's no change to our roughly $2 billion per year. As I said that, $2 billion -- when we say roughly $2 billion, that can exceed $2 billion, that could be $2 billion, $3 billion, or something like that I think and CapEx can be lumpy depending on the timing of that. So, you got to keep that in mind. But it's something that we review every quarter and that we reviewed before coming into the call this quarter and we'll do so in January of next year. So, we try to keep you up to date on that, but no change at this point. I'd point out that with the cash flow that we generate, we can fund roughly $2.5 billion per year in CapEx out of our cash flow. And then in addition to that, we've got some balance sheet capacity should we need it to be able to fund projects and bring down leverage as they come on. So, I think we're in good shape in terms of being able to fund projects, if we were lucky enough to take that number higher.

Got it. That's great color. Thanks. And then my other question was really about expected returns. So, obviously, the backlog has lots of different projects, different sizes, types of projects. But if there's anything, just talk about trend-wise, are you seeing better returns on this project? It seems like the South System 4 Expansion was a really attractive multiple versus your total backlog. So, just wondering if you're seeing that trend overall. Thanks.

I mean I think the returns that we are getting on these projects are pretty consistent with what we've achieved historically and what we've targeted. So, different projects come at different returns depending on how long it takes you to bring a project on, the multiple is likely going to be better to get to the same return because you've just got that, you've got that CapEx drag on the front end. But no, South System 4 is not substantially different than the projects that we've done historically.

Thank you.

The next question in the queue is from Theresa Chen with Barclays. Your line is open.

Hi, Theresa. Theresa?

Please check your mute button.

Can you hear me now?

Yes.

We can hear you.

Sorry about that. So, looking at your Mississippi crossing project, can you give us some color on the commercial drivers that would allow Kinder to win this project, assuming the binding open season is successful? Do you think this is in part driven by customers' desire to diversify sources of supply beyond the typical Northeast mid-Atlantic corridor?

Theresa, good question. One, I think as we've been saying before, with the advent of all this LNG coming on in the Gulf Coast, I think the markets are recognizing the need for incremental supply. And this is not only diversification of supply but actual access to physical molecules to be able to handle the upcoming growth. And so I think reaching back to a point of liquidity where you have access to different basins in addition to the existing basins is kind of the play.

Got it. And then turning to a different part of your portfolio. With the recent success of one of your competitors in spinning out their liquids business, any thoughts on separating your products business from your natural gas assets to potentially reflect better value in each?

Yes. I mean, I would say we -- the businesses that we own and operate, we think they are strategic to owning together. We get benefits from owning natural gas and products pipeline. For example, on the integrity side, our integrity team is one that goes across on the ER. On the project management side, we get benefits from that. And so, I think there would be certain dissynergies if you spun those businesses out. I also don't think that, if you look at some of the parts, where we're trading today, if you peel those businesses apart and look at them versus where you look at the Company together, there is a significant discount. And so, there's not a big incentive to incur transaction costs, dis-synergies probably on the G&A side, and dis-synergies potentially on the debt side. That just depends on where interest rates are at the time you would do a transaction like that, but that would make sense right now. It's a very market-dependent transaction. And so you've got to have very strong views about where the companies would trade in the aftermarket that are significantly different from some of the parts in order to justify taking on that kind of risk of spending -- of breaking up a Company.

Thank you very much.

Next question is from Zack Van Everen with TPH. Your line is open.

Hey guys, thanks for taking my question. Maybe to start, could you guys touch on the recent decision with the U.S. courts on your Cumberland project and kind of what the process is there going forward?

Yes, sure. And so, as you know, the Sixth Circuit estate, our Army Corps, and our Tennessee air permits or water, water permits. You know what that effectively does is it prevents us from starting construction on that project. So, we believe that decision is wrong. We believe the analysis is flawed on multiple levels, including the standard that they applied for the stay. That's a project where we are delivering natural gas to a natural gas power plant that is converting from coal. And so, here the FERC found that that project would result in a reduction of greenhouse gas emissions. So, it would be good from a greenhouse gas perspective. So, over the last 10 years, our permits, whether that's federal, state, local, have been challenged by anti-fossil fuel opponents, regardless of the benefits to society. We have been very successful in winning those court challenges. Recently on the DC Court of Appeals, they upheld our FERC permits on two separate projects. So, we were also successful in other courts on state and local permits related to those projects. And so we've had -- this isn't something that is new for us, but we're working with the impacted agencies, the Army Corps and TDEC to determine next steps and I think both of those agencies are going to vigorously defend those permits.

Perfect. That makes sense. And then maybe one on the FID on Gulf Coast Express. I think when looking back to Permian Highway, that took about a year. Is that a similar timeline you guys are looking at for this expansion?

Yes. Permian Highway took about 19 months. Here, we're probably kind of conservatively saying 22 months given all the -- there's quite a bit of demand on compression and some of the electrical components. That being said, we're targeting a mid-'26 in-service date. So, not quite the 19 months on PHP, but we don't see it being that far out of the realm.

Got it. Makes sense. Appreciate the time, guys.

Next question is from Jean Ann Salisbury with Bank of America. Your line is open.

Hi. Between the Gulf Coast expansion and Blackcomb, there's a lot of gas heading to the Agua Dulce area. Is there a risk that there won't be enough demand in the area in 2026, especially if LNG projects get delayed? And how do you see the GCX expansion is positioned for that risk?

So, good, very good question. I think, look, if there's any delay to the demand centers, particularly the LNG demand centers, could there be some pricing exposure? Yes. That being said, for us, part of the -- our discussion points have been, we've got some downstream optionality on our networks for our customers. And so there is -- so that embedded optionality. At the end of the day, when you have that kind of variability, there's going to be some volatility, which storage assets come into play and really that's where I think that becomes increasingly important as we move towards that timeframe. It's a possibility, but not a probability. We don't know yet.

And from our standpoint, we have long-term contracts with our shippers.

Yes. So, we've got long-term contracts with the shippers. I always though point out that it's a potential for us to profit on our Texas Intrastate business where we do buy and sell some gas and we try to back-to-back those, but sometimes we are in the daily markets. And so to the extent that that gas gets hit at Agua Dulce and we've got capacity on our pipeline, we can buy effectively cheap gas. And so that will be an opportunity for us. I think the other thing on that is, we do have a project that we've been working on to potentially expand our pipeline systems from Agua Dulce up into Katy. And so if that could create an opportunity for that project just depending on how long that dynamic was anticipated to persist.

That makes sense. Thank you. And then at your Investor Day, you kind of mentioned that you have 200 Bcf of market rate storage. Bringing that up to current market rates is going to be kind of a tailwind. Is that still a tailwind that you see over the next couple of years? Is that mainly still below kind of current rates, if that makes sense?

Yes. It's about 25% of our storage is market-based rates. Some of that we have rolled and some of it we still have to roll. But in terms of the strength of the storage market, the strength of the storage market is continuing and rates, I think are continuing to get a little bit stronger. On Monday, we talked about a three-year deal that we've done. That was a high watermark for us on the storage side. That was in five-turn service. So, I mean, very valuable storage, but we did hit a high watermark. So, I think that's still going to be a tailwind, but those contracts probably roll over a three-year period roughly. So, you probably roll a third of those a year.

Great. That's helpful. That's all from me. Thanks a lot.

Next question is from Neal Dingmann with Truist Securities. Your line is open.

Good afternoon, all. First, my first question, just more general on backlog. And I'm wondering, is it fair to assume that we should think of your backlog maybe staying around the $5 billion given, number one, it seems like you have a lot of opportunities you discussed, but you also have, I know, a number of projects that should come on to service in the coming quarters and just wonder how you would expect to think about this?

Yes. We haven't tried to do a roll forward of our backlog yet, Neal, so I can't really tell you exactly directionally where we're going. As I said, it's increased from $3.8 billion, a year ago. We do have projects rolling off, but I think we -- there's a potential to add some significant projects in addition to, I think, singles and doubles. And to the extent that we add those really significant projects, I think there's potential that, that backlog grows.

That's great to hear. And then just secondly, I know, a bit smaller, just anything you could add on the CO2 portfolio specifically. I know I think last quarter you mentioned just likely no material change in capital spend there. I'm just wondering, will this continue to be the case? I know you've got what, given the development of SACROC and North McElroy are different things, how should we think about that portfolio?

Yes. I think, Tom mentioned in his comments that we just recently -- well, this quarter, yes, this morning, our Board approved about $150 million of projects in CO2 and those are really new CO2 floods. And on peak production, that's going to get us an incremental 5,000 barrels a day, which is a pretty significant amount on -- as a percentage basis of the existing production. So, Anthony?

Yes. On an annual basis, we're spending probably $200 million a year on expansion. So, I think that just rolls into that program. So, I wouldn't expect a material increase at least in the near-term.

Very good. Thank you both for the details.

Next question in the queue is from Jeremy Tonet with JPMorgan. Your line is open.

Hi. Good afternoon.

Hey, Jeremy.

Hey. Also wanted to give a belated happy birthday to David there.

Thank you, Jeremy.

You know how old he is?

I don't think I'm allowed to ask that. But just wanted to kind of pick up on a couple of pieces that were touched on a bit during the call. Kim, I recognize this is kind of an impossible question, but just at a high level, when we think about operating leverage for Kinder, there's weight and capacity on the gathering side. There's weight and capacity on the pipe side and just want to get a sense for, I guess, capital-light growth there. If the G&P really ticks up, if there's a call on gas, higher gas prices, if the peakers are really pulling because they have to run more given high power prices, how does that, I guess impact KMI?

So, I think there is capacity on some of the gathering, especially in the Eagle Ford. We'd have to add some processing in Eagle Ford. But from a pipe standpoint, you've got plenty in the Eagle Ford. In the Haynesville, we've got a big backbone. But we'll need to add some laterals, potentially some treating depending on what's going on there. I think lateral is probably required in the Bakken, but again, pretty efficient expansions on the gathering and processing side. On the transmission pipes, those are running pretty full as you've seen from some of the utilization that we presented at our conference. And so there, I think more of the upside is going to come as contracts roll. So, it doesn't necessarily -- and then as we can provide some ancillary services around volatility events, I think is where you'd see some tailwinds on those pipes that run at pretty good utilization.

Got it. That's helpful there. And then just wanted to kind of touch on a little bit more as it relates to the power demand, large customers as well as data centers, potentially. How far upstream could you guys see Kinder going? Could Kinder provide behind-the-meter gas solutions, be it providing the gas or if there was a contract structure that was attractive, even providing the power itself with the gas generation? Just wondering how you think about the opportunity set here.

Yes, sure. I mean, providing gas directly to a power plant is -- we can do that whether it's behind the meter or in front of the meter. I mean you're asking is it going to be part of the transmission grid or not. I mean that doesn't really impact us. So, we can provide the gas in either scenario on that. We've talked about from time to time, could you have put a power plant next to one of our storage facilities and that would give that power plant very high reliability and then it would also give great reliability potentially to a data center that was located near. We don't have any concrete really plans on that at this point, but it's something that we are looking at.

Got it. That's helpful. Thank you for that.

And the next question in the queue is from Keith Stanley with Wolfe Research. Your line is open.

Hi. Thank you. Just two clarification questions. So, the first one, I think you said you could fund $2.5 billion a year of growth CapEx out of cash flow. Would you be comfortable even going higher than $2.5 billion a year on a recurring basis, or do you view $2.5 billion as kind of a cap within your financial framework?

As I said, right now we're at 4.1 times debt-to-EBITDA. We expect to end the year around 4 times debt-to-EBITDA. The high end of our range on debt-to-EBITDA is 4.5 times, every 0.1 is, roughly $700 million-ish. And so, I mean, you could -- we could debt fund, if you will, some incremental CapEx as long as we were sure that over time based on the cash flow that these projects would bring on, and I think based on the returns that we target, that would occur, that debt-to-EBITDA would come back down over time. And so, that's something that we can do. The other thing is, I mean, our view is when we -- good return projects, we can find capital for. And so, if there were some really, really large projects, we could also get partners on those. So, I don't see a problem being able to fund good projects with good returns, whether it's 100% on us or partnering with private equity or somebody else.

We think we can maintain a strong balance sheet and still accommodate our needs for CapEx.

Thanks. Makes sense. Second one, just on the -- I wanted to follow up on the court's question. I mean, some of your peers have been affected a little more, but do you see more risk generally with court reviews on projects post the Chevron decision, are there different things you can do on permitting strategy, timing of when you deploy capital, thinking about return requirements to deal with it, if the courts are becoming a little more problematic on new infrastructure?

What I would say with respect to the Chevron doctrine and this decision is, I don't think the Chevron doctrine played any part in the decision we got on Cumberland. And, I think that this is something that we've been seeing. I mean, even if you go back to PHP, I think we had five or six separate matters that got challenged as we were going through PHP and we had like 14 different hearings that we were successful on. And so, I think this is something that we have been seeing for a while. Yes, there are things that we can do to try to make the situation better. I think as we work through permits, it's not sufficient just to get a permit. We have to make sure that we're covering all the bases and doing all the work necessary to try to make these -- the permits that we receive defensible in court. And I think that I don't -- so, I don't see it right now being more difficult than what we've seen in the past. I think people should expect that we're going to get challenged and that we're going to work that into our strategy. We're going to work that into how we deploy capital and we're going to figure out how to overcome that as we do these projects just as we have for the last 10 years.

Thank you.

And I'm showing no further questions at this time.

Okay. Well, thank you all for joining us this afternoon. Have a good evening.

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