No obvious reason for me to stand, but I'll stand anyway. Good morning, this is the 41st Annual Strategic Decisions Conference. My name is Bob Brackett, Bernstein's Head of America's Energy and Transition. We are not expecting a fire drill today, so if the alarms ring for any reason, please take it seriously. The primary route of exit, luckily, is straight out the door, to the back of the room to the right, and you'll descend an inside stairway a few flights and exit to the north. If, for any reason, that exit is blocked, you'll go out the door to the left, back towards the lobby, and there are three or four internal staircases that will bring you down. This is your conversation; this is your fireside chat. On the screens around you, you'll see it rotate through.
It'll show a QR code for you to enter your questions into Pigeonhole. They will show up on my screen up here, and I'll launch into that conversation. While we're waiting for you to drive the conversation, I will start by introducing Kimberly Dang, the CEO of Kinder Morgan. My conversation will start in the shape of a pyramid. We'll start with the macro questions. We'll move down into strategic questions, financial questions, and then operational questions. With that, thank you, Kim, for joining us.
Thank you, Bob.
We'll launch in on my favorite topic of the year, which is natural gas. You all have a forecast for gas demand growth of plus 28 BCF a day. For the audience, U.S. gas demand's roughly 120, so we're looking at a 25% growth in something that's hard to keep flat over the next four-ish years. That's well ahead of consensus. It's a smidgen behind our forecast, and frankly, every time we refresh our forecast, it goes up. Talk to your enthusiasm around natural gas.
Sure. I mean, it is a, it's a very exciting time to be in the industry. I've been at Kinder Morgan now for 24 years, and this is some of the best opportunities we've ever seen in the space. So, you know, as you said, our forecast for gas growth is 28 BCF a day, I think. Wood Mackenzie's most recent forecast they just came out with is 22 BCF a day. So, you know, significant growth in the market, driven primarily by export LNG. You know, we'll call it 15 BCF-18 BCF a day of that 22-28 is associated with export LNG. And then you've got incremental power demand, you've got incremental industrial demand, some rescom, and some exports to Mexico. So, you know, really seeing some nice growth across the board.
You know, what that's done, first of all, that's, you know, that's 22-28 going forward. If you look at what we've seen since 2015, we've seen over 30 BCF a day of growth since 2015, and that's really filled up the existing pipeline system, and storage is highly utilized at this point. You know, you've seen some price increase, significant price increases over the last few years in storage services. You know, the pipeline systems are full, and so, you know, the incremental demand is driving growth. You know, we've got an $8.8 billion backlog of projects, 90% of that is natural gas. Natural gas is about 65% of Kinder Morgan's overall business. You know, that $8.8 billion is largely backed by take-or-pay contracts.
If you look at it, you know, seven and a half of the 8.8 is largely associated either with take-or-pay or fee-for-service businesses. The balance is EOR, which is our CO2 business, and our gathering business, gathering business, and primarily natural gas, a little bit in crude. Those projects are, you know, we've got locked-in contracts, they're approved by the board and moving forward. Obviously a big opportunity in front of us in terms of the growth.
If we talk about the big demand drivers for natural gas, we can start with LNG. We know LNG is export. We know with high certainty it's going to sit on the Gulf Coast, and we know there's not enough gas on the Gulf Coast to feed that. Someone needs to connect that gas. Talk to your role in connecting into LNG export.
Sure. It's interesting when you start looking at LNG export, and this is something we've seen evolve over time. You know, generally for the export facility to go get its financing done, it signs up for pipeline capacity. Usually they build it. It's a header going from, you know, a liquid point to the facility. As they progress further towards construction and further towards in-service, you know, they start looking at, "Oh, well, you know, where I'm buying that gas, it's a very competitive price, and I'd sure like to get, you know, some cheaper gas." Then they start looking back upstream to expand back, you know, closer, not to the wellhead, but, you know, back upstream to get a more attractive price point.
A lot of times they also, you know, are looking to diversify supply and/or pipeline capacity. You know, they're not, it's not a one-for-one in terms of the capacity they sign up. You know, they want some insurance, so they may sign up for 120% of their needs or 130% of their needs. Every LNG project brings multiple opportunities.
We move to power demand. One of the things I've been arguing is a lot of people shortcut power demand growth as they call it AI growth, or they call it AI data center growth, or whatnot. Clearly it is something around, data centers matter, that, that, commercial demand matters. We do not know where it's going to be placed. There is a competition perhaps between data centers being built in areas that already produce natural gas. You could imagine the Permian, you could imagine Appalachia, versus data centers being built in Louisiana, which have been sanctioned, where you have to bring the gas from somewhere. How does that tension evolve, and how do you compete with siting of data centers?
Sure. Let me start on your point about, you know, power demand is broader than just data centers because, if you look at our backlog right now, 50% of our backlog is associated with power, which most people would think, "Oh, LNG's the big driver." You know, 25% of our backlog is associated with LNG, but 50% is associated with power. We are seeing multiple drivers of that power growth and that power demand. One is you've seen population migration to places like Georgia and Alabama and Texas and Louisiana and Arizona. That population comes with a need, you know, for more power. You've seen businesses migrate, and then you've seen an onshoring, and that is ongoing, I would say, of industrial capacity, manufacturing capacity.
Think about things like auto production in Alabama or chip or battery facilities out in Arizona. A lot of industrial and business demand, incremental in the southern United States, along with the population growth. You also are seeing, you'll be seeing coal retirements. Those coal plants are being replaced with natural gas facilities a lot of times at the same location, so your coal conversions, if you will. Then you have data center demand, and that's also a driver of the power. You start looking at all those, and typically on the population and the industrial growth, that's going to happen near the population centers. Coal conversions a lot of times at existing sites or all the conversions are at existing sites.
That's happening around population centers because, you know, it's very expensive to build transmission. The power plants are going in and around the population centers, the industrials going around population centers because they need workers. You know, the data centers are interesting because they have some more flexibility as to where they locate, because you can site the data center and the power plant together, and then build the fiber to the market. Now, if you build the fiber over too long a distance, my understanding is that, you know, you do get some latency. I don't, you know, they don't want to locate too far away from the market areas, but, you know, they're really looking, I think, at speed to market.
Where we see right now, the most near-term opportunities, you know, is really around where the regulated utilities are building power plants. That is in places like Arkansas, Louisiana, Mississippi, Georgia, South Carolina. Those are where we see the more near-term opportunities. I mean, that is also where we have the infrastructure, so that is where we are going to see more opportunities because a lot of our infrastructure is in the southern United States. Quite frankly, our infrastructure is in the area where we expect most of the natural gas demand growth overall. 85% of the natural gas demand growth that is expected is coming, you know, in the southern and southeastern United States. It is good to have a position where the growth, a nice asset position where the growth is occurring.
Everyone's moving south. The electrons are moving south. The methane's moving south. If I think about some of the companies we'll have here this week, a $1 move in Henry Hub or a $10 move in oil can move their cash flows 40%. Those CEOs wake up and they look at their relevant commodity price. You've got something like a 1% sensitivity to changes of that magnitude. When we talk about the gas opportunity, do you care about gas price or is it just gas demand and gas volumes?
We care more about gas demand, you know, but in the long term, you know, what impacts our customers impacts us. You're right, our direct commodity exposure is pretty modest. If you look at our EBITDA and break it down, 64% is coming from take-or-pay contracts. You know, 26% is coming from fee-for-service business, so no, no price exposure. There you have some volumetric exposure. 5% has commodity exposure, but we have a multi-year hedging program, and then 5% has the commodity exposure, most of which is crude, but some of which is gas. That's where you get the relatively small sensitivity to commodity prices. When we go out and we sign up long-term contracts to back these projects that are in our backlog, we're getting generally long-term take-or-pay contracts from people.
You know, we're not as concerned about what the, you know, price is day-to-day of natural gas. And, you know, before they go on our backlog, generally we have to have long-term contracts underpinning those. I think the $8.8 billion, seven and a half of it, that's not the EOR and the GMP, those we have locked-in contracts. That growth is going to come. And then, you know, beyond that, what you want is prices to stay in a somewhat reasonable range. You know, I think when you start impacting demand or you start impacting supply is when you get prices on the extreme ends. We prefer things, like Goldilocks, kind of just right in the middle.
I think, look, I think with the discipline that we've seen from the producers, their ability to put ducks in inventory, their ability to do TILs, you know, hopefully, you know, we can avoid some of those extremes that we've seen in the past.
I mean, clearly 2024, we're sitting at $2 gas, the cheapest hydrocarbon near a demand center on earth. And clearly that wasn't sufficient for the industry. Even the lowest cost producers, supply fell. That's the bottom of the Goldilocks. What gas price do you think is the top of the Goldilocks cycle? Too high for demand destruction?
That's hard. I mean, we clearly saw some demand destruction when prices were at eight and nine, and, you know, people were hesitant to sign long-term contracts. I would say when you get to that level, there is, you know, that's when you start impacting things. You know, it's harder to say if you were at six or seven because we went to eight or nine and then, you know, we quickly dropped back down. Hard to say exactly where that point is, but I think when you get to eight or nine, you clearly are there.
Yeah, I like that range. I'll take that. I could argue that the eight or nine is a discounted price into Europe. Asia and Europe pay more than that today. They'd smile at that price, but, moving to the regulatory environment, what do you see there today? People have talked about the ability of the oil and gas industry to permit projects, permit pipelines. I've always had a philosophy that there's more than one person that decides to put a pipeline in place, and there is a federal process, and there is a state process, and there is a local process, and there is a community process, and there is a board process. Clearly the federal scope has changed. What do you see there? What would you like more clarity in?
Sure. The federal process is getting better, and, you know, both from, you know, regulatory burden and cost. The first couple of things that we saw by the current administration was, you know, they took back the Clean Power Plan. That helps us indirectly in terms of power demand. They took back the Good Neighbor Plan, which was going to cost us significant dollars of spending. Oh, and the greenhouse gas reporting, which, you know, was a burden, not as significant as the Good Neighbor Plan, but still an added incremental burden. They did those things off the bat. We have seen many of the different Corps offices announce new regulatory guidance, which expedites permits coming out of the Army Corps of Engineers.
That's been good to see, you know, as we've been working with the BLM, so the Bureau of Land Management, as we've been working with Fish on some projects, we've seen them much more responsive and much quicker to get decisions. That's been good. We filed, through INGAA, through the trade association, INGAA filed with FERC some actions that could help FERC speed up permitting. Specifically, one is called Order 871, where the FERC has five months from the time they issue our permit until they grant us a notice to proceed to allow for any rehearing request. You know, they put that in effect without notice and comment. We've asked them to take it back without notice and comment.
You know, the Energy Dominance Council has filed a letter in support of INGAA's filing to do that. That would be a big dent into some of the time and permitting. You know, we're seeing some good changes. Where we're building on the state front, most of our projects again are in the South, Southeast. There, generally we have pretty supportive regulatory bodies from a state or local perspective. You know, we have not needed much change in those areas. Generally, their timeframes were well inside any of the federal timeframes.
We can generally get those things done in the timeframe it takes to get the federal permit, even if you shave off time from the federal permit. You know, where it'd be nice to see some more changes is really on the judiciary, and people's ability to challenge permits. There is some language in the current reconciliation bill, the one big beautiful bill, I guess they call it, that basically limits the people that can file challenges to these permits to people that are, you know, directly harmed and the harm is imminent, and to organizations where every member has to be, you know, directly harmed. They have increased the standard for finding that the permit is invalid.
You know, if something like that got done, I think that's probably going to get challenged in terms of being part of the reconciliation in the Senate. Not clear to me that that's going to pass. You know, things that, on the regulatory side, I think do help even currently. You know, we have been successful on some of our court cases. The most recent one we prevailed on, lateral we were building for the TVA to one of their converted coal plants. We prevailed on that court case. You know, I think the decision in North Dakota with respect to the damages assessed against one of the NGOs, that's going to give them some perspective about which things they choose to fight.
I think the defunding, you know, to the governments, some of the NGOs could also help, on, you know, on the, on the judiciary side. So we are seeing some things that help. You know, it'd be great to get more if you could get something like the, the language that's in this bill. I'm not sure it's going to pass, through the reconciliation, but maybe down the road we could see something there.
I'm going to try, I'm going to weave that into how you think about capital allocation. If we think about maintenance capital running about $1 billion and not impacted, I should assume, due to regulatory issues, $2.5 billion of growth CapEx against an almost $9 billion backlog. So you got lots of things to do. Where does that regulatory burden come in? Does it cost you time? Does it cost you cost? Does it cost you deliverability?
Generally, the regulatory cost, in sustaining CapEx, in terms of the regulatory burden on an ongoing basis, that's going to sit in your $1 billion of sustaining or it's going to sit in your OpEx. You know, if we were having to comply with something like the Good Neighbor Plan, which was proposed to be an added regulation, that's where you would see that. In terms of, and then, you know, if we're doing a new project, obviously we would put that in a new project in the O&M and in the sustaining. It would also have an impact on our ability and our willingness to move forward with projects. We would take it into account, you know, both places. I think, you know, that would just make rates on pipes more expensive.
You effectively pass it on. If we stay on that theme of the capital, you have one hurdle rate you talk about, less than six times EBITDA, or six times, greater than six times EBITDA for CapEx. What else governs capital allocation?
Sure. Bob's referring to, on our backlog, we publish a multiple that we expect to earn on those, and it's less than six times EBITDA multiple on the $7.5 billion. That's where we estimate it for people because that's where we have the contracts. I think the multiple's less telling when you have a GMP project because you have a high front-end multiple, but that comes down over time. It's not as indicative of the ongoing cash flow. Less than six times, but that's not how we look at it internally. That's just something that we provide externally to give investors an idea about the types of returns we're earning on these projects.
You know, when we're thinking about things internally, we're looking at, you know, an unlevered IRR. You know, we have a threshold set for that, and then we vary that threshold based on the risk of a project. If you have something that has commodity exposure, then you're going to have to, you know, it needs to be higher than that threshold. You know, if you have something that has 30-year take-or-pay contracts from an A credit, right, then you can come down from that threshold a little bit. That is how we, you know, we guide our development teams. They have a pretty good idea of the type of projects that we're looking for and, you know, what we want to do. We tell them, you know, projects are on the margin.
If you think something's on the margin, come in and let's talk about it. Let's see if we can get there, you know, on it or not. At least, you know, the ones that they know, you know, might get done, we want to have a conversation about.
In terms of capital allocation, what, in a previous life as a strategist, one of my definitions of strategy is tell me what you won't do. What won't Kinder Morgan do?
A lot of people have been asking us about, would we build power plants lately? Because there's a lot of demand for power plants. You know, that's just, that's not what we do, and so that's not something that we're interested in doing. You know, we build pipelines, and we can build storage facilities, and that's what we're good at. We're going to stay in our lane on that. You know, we have stepped out at various times over my career at Kinder Morgan. You know, generally the first model of something's, you know, not a great experience, just like the first time you do something, you know, it's probably not your A product. We've had experience actually with building power plants in the early 2000s when we had the last big natural gas power plant build.
and, you know, it was, they were late and there were cost overruns. We are just going to stick to our knitting.
One of the questions I used to ask, in funding projects was, ask the engineer on the team, hey, what's cool about this project? And if the engineer says three things that are cool about the project, discard the project. It's the big boring ones that make money. In terms of, again, what you might or might not do, we have a question, from Pigeonhole. How do you think about the role of M&A in your capital allocation strategy?
I think we are always looking at M&A, and so we always have a strong appetite. It is a question of does the opportunity meet the criteria that we have set out? We have three primary criteria. You know, one, it has to fit our strategy to, to the discussion we just have. Is it a stable fee-based asset, core to the energy infrastructure? You know, the second is, you know, has it got a decent return? We are looking at unlevered IRRs, we are looking at accretion and dilution on a per share basis, and then can we do it within our balance? Can we accomplish it within our balance sheet metrics? We have 3.5 times-4.5 times debt to EBITDA range that we have set as where we like to operate.
We look at whether that can be done within that threshold. If you look at, you know, what we've done in recent years, this year, earlier this year, we did an acquisition in the Bakken, you know, a little over $600 million to add to some very integral, with some of our existing gathering and processing assets that we have up there. Early 2024, I think we closed at the last week of 2023, you know, we bought some pipeline assets in the Texas interstates, you know, a big system that goes in from Texas down to the border, and so, you know, that was $800 million-ish. Prior to that, we did an acquisition of a natural gas storage facility in the Northeast, which was, you know, a billion-ish, over a billion dollars.
Those are the type of things that we've found recently. You know, we built this company on acquisitions. We know how to integrate things, and we've done some big ones in the past, but it's a function of can you find things that meet our criteria.
Another question coming in on Pigeonhole. How does Kinder plan to grow its business beyond traditional infrastructure? What new technologies are you exploring?
You know, we are like every other company in America, you know, we look for opportunities to deploy AI. You know, we are finding opportunities within our business to help us make better decisions, using AI. You know, I give a couple of examples. You know, one is with respect to when we introduced drag-reducing agent into the pipeline. On products pipelines, you know, they are running booster stations. We are batching the product through the line. When power prices get really expensive, you know, it is cheaper to stop using some of that power and introduce drag-reducing agent into the pipeline to sort of slick it up and make the barrels flow more freely. You know, we have introduced AI.
It, you know, predicts when power prices are going to stay high for long enough that it makes sense to introduce the drag-reducing agent. You know, we are using AI to help us, you know, decide, and, you know, when we can sell transport capacity and when we should not be selling some of that transport capacity. We have got a number of different applications. We are also using it to effectively create an enterprise-wide system. It can pull all of our data into what we call a digital twin. We can access that data using a large language model because, you know, we have got different types of businesses. We have got products pipelines. We have got refined products terminals. We have got natural gas.
You know, bringing all that system, all those disparate systems into one digital twin, you know, I think will allow us to make better, quick, more real-time decisions.
You mentioned the refined product part of the market. Gas is two-thirds of what you do. Refined products come in at about a quarter, let's say. I have high conviction that gas demand is rising. I hear that you do too. I have no conviction that refined product demand in the U.S. is rising. OECD in general is past peak oil demand. The U.S. is in that camp. What is the longevity and what is the focus of what you're doing in refined products?
Sure. It is interesting. You know, we have had multiple different projections over the last four years. You know, I think they are getting a little bit more realistic now because I think in the introduction of the EV, you know, people were thinking, oh, the EV is going to overtake all the ICE demand. You know, what we have seen is that, you know, it had a very strong growth trajectory at first, but now it is sort of leveling off. You know, depending on how you classify the different vehicles, I think, you know, it is about 8% or 9% of the market right now. It was there last year and it is in that same range this year.
You know, I do not, you know, before we thought, you know, maybe it may be about a 1% impact on long-term demand. That is 1% decline in long-term demand per year. You know, more recently, I think our projections are below half a percent, you know, on most of, you know, well, on our refined products pipelines, you know, we have a tariff, inflation escalator. Every year, we inflate at CPI, PPI, + or - a FERC adjustment. Right now that adjustment is + 0.78 and they are going to reset that at some point. You know, just think about, you probably get over the long-term 2%-3% price increase on those pipes. You have less than a 1% volume decline. You know, I think you will see those, those, they will produce stable cash flow. You will get a little bit of growth.
we'll have, you know, some small, expansion opportunities from time to time based on shifts in the market. but largely that cash flow will go over the next four years or five years to fund all the growth that we have in natural gas.
The third business that we haven't talked about, if we think about Landman, the Paramount series, season two is going to be about shale, right? Season one was actually about the old stuff. CO2 is an old stuff business in the Permian. It's much more season one. It's not when people hear CO2 from oil and gas companies, they often think sequestration, they think future-facing, less so for you. It's an existing business. Talk about that business and put it in context.
Sure. I'll give the layman's explanation of our CO2 business because that's what it took me to understand it. You know, primary production, you go out, you poke a hole in the ground and here comes the oil. Over time, the pressure in the reservoir subsides. Generally what people do is they push water down into the reservoir to force the oil out. You know, that's secondary production. That's kind of a brute force method. Tertiary methods involve some other medium other than water. The primary one that's used is CO2, but there are others. CO2 acts like, you know, turpentine on your paintbrush. That's how it, you know, with oil in the reservoir.
It kind of slicks up that oil, moves it out, and then you follow with the water to move it into the production wells. It is more what we call a finesse method of getting the oil out of the ground. Really what you are doing when you get to that level is, you know, the oil fields have gone through their huge peak of primary production, have come way down the decline curve. All you are doing is trying to extend that decline curve out for a few more years. We have been in this business since the early 2000s, and we have got two primary fields out there where we inject oil and produce CO2. That is roughly 5% of our overall business.
Then 2% of our CO2 business is really selling the CO2 to third parties who use it to flood their own fields, you know, like Oxy or ExxonMobil or some of the other majors who flood using CO2. You know, generally these CO2 floods, especially where you have existing infrastructure, are going to make sense down to, you know, less than $40 or less, on a price basis. In fact, you know, I think our cost out there on some of this stuff is maybe $20 at some of our higher fields and, you know, low teens in terms of some of our others, even including the cost of CO2 on a marginal basis. You know, it makes sense to produce those well below the prices where we are today.
and then the other 2% of that business is just, primarily RNG, renewable natural gas, capturing natural gas off of landfills. That's all, you know, embodied within our CO2 segment, which is 9% overall.
We have a question. Can you talk to the renewal rates and pricing trends for existing contracts?
Sure. It depends on, you know, the segment that you're looking at. If you look at natural gas, and you look at the large diameter pipes there, I think our average contract length is probably going to be seven-ish years in that range. If you do that, you're rolling off one seventh of the capacity every year. I talked about earlier the 30+ BCF a day of growth that we've seen in the natural gas market has really filled pipelines up. That generally bodes for increasing rates when you're renewing those contracts. That being said, we do have our interstate pipelines regulated by the FERC and those are rate regulated.
There is a cap on what you can charge on those, on our unregulated pipes. Those are primarily in the Texas interstate market. You know, you do not have that same cap. Storage facilities, you have got the same split. Storage has been, is highly utilized. When you are renewing that, to the extent that you are in an unregulated market, you can get a price uplift. To the extent that you are already at max rate, then generally you are getting longer term, because there is an ability to increase price.
We have a question. If we come back to your CapEx backlog, that almost $9 billion number, three of the biggest projects in there are gas pipes, south, southeast gas pipelines. Do you have any big gas pipeline projects on the horizon? Maybe talk to those three and then talk to any bigger ones you are ready to announce today.
I think so. Okay. The three big ones, one is in the Texas interstate market and it is taking gas from around the Houston area back up and around over into Port Arthur. It's primarily serving export LNG, and so, you know, that is a billion eight in capital roughly. We've also got a pipe, Mississippi Crossing. We come up with very original names, that goes across the state of Mississippi and feeds into an expansion that, and that's a greenfield pipe. It feeds into an expansion that we're doing on South System Four, which is our pipeline system that goes through Alabama and Georgia. Those two pipes are largely driven by incremental power demand, and then partially by some LDC demand. So just pure natural gas. A recent project that we announced is our bridge project.
That's about a $400 million project that is going into the state of South Carolina, and it is power data center related. That's backed by the Carolina LDCs, power companies. A lot of great projects, you know, it's, you know, those projects, $5.5 billion of cost to our share, you know, over 5 BCF a day. That's a, you know, that's a, those projects are a huge portion of the existing backlog. They're very exciting projects. The Texas projects will get done sooner because they're in an unregulated market. You don't, you know, we don't need the same perm, we don't have the same permitting requirement to go through FERC.
On the FERC pipelines, I'm, you know, optimistic that, you know, we're going to get things permitted more quickly than what we've seen in the recent past based on, you know, some of the things the administration is doing. We are out there locking in cost, you know, locking in the cost of our pipe, locking in the cost of our compression, make sure we bring those things in on time and on budget.
If we talk about financial strategy a bit, maintenance CapEx claims $1 billion. They are at the front of the bus. The dividend claims $2.5 billion-$3 billion or so. Talk to the sanctity of the dividend and the growth of the dividend.
The dividend is very important, and we think we have it set at a level where we can maintain it, as well as grow it very modestly, consistent with what we've done over the last few years. We think that's important. We've got a lot of dividend investors in the stock and we think it's important to show some growth. That being said, we haven't been growing it at the rate that the company's been growing, and that's because of all the expansion opportunities that we have there. We want to preserve that capital to invest in these high-return projects. When you think about our cash flow post, you know, post-sustaining CapEx, I mean, you can think of about roughly half goes to the dividend and roughly half is going to expansion CapEx.
The part you left out was, the balance sheet. Net debt to EBITDA stands at 4x, your triple B. Sounds like that's the right level.
Yeah, we think that's the right level. You know, given the size and the scale, and the diversity of our assets, you know, we've got 80,000 mi of pipe, you know, 65% gas, the 25% roughly is refined products. And then we've talked about the other 9% being CO2. So you've got diversity and scale and scope. And so we think three and a half to four and a half times is the right level. You know, we run a lot of economic analysis to look at whether, you know, paying down debt, and, and, you know, reducing leverage would be the right thing. And that is not, you know, an economic proposition. And so, we feel like this is the right level. Personally, I think we are underrated by the rating agencies if you map out based on their criteria.
Recently S&P has put us on positive outlook. We're triple B flat right now and they put us on positive outlook. We've been at or below four times for the last several years. You know, just depending on the level of CapEx depends on where in that range we end up on any given year. I think, you know, our goal is to stay within that range as these projects come online. You know, the EBITDA from these projects, I mean, that will strengthen the balance sheet if we're fully funding with internally generated cash.
How do you handle that tension of an exciting backlog that I would expect gets even more exciting and larger and working through it $2.5 billion a year on a $9 billion backlog? What's the desire to raise, you know, go half a turn up on net debt to EBITDA and pull some of those projects forward? How do you find that tension?
I think we do, you know, show an in-service by year. Right now, I think $2.5 billion is kind of the right number. I mean, some years it is going to be $3 billion and other years, you know, it could be a little less than the $2.5 billion. It, you know, just depends on exactly when you get your approvals on some of these pipes. It is not, you know, it is not going to be perfectly smooth.
I think because, you know, we're sitting below four times, and the top end of our target range is four and a half times, you know, to the extent that you have a year where you're going to spend a little more, you know, you're going to be fine because the next year you'll spend a little less and you'll come back into line. To the extent that, you know, we have more opportunities than, you know, what we can do, we sort of living within cash flow during the next few years, you know, I think that'll be great. You know, we do have some balance sheet capacity. These are, you know, long, you know, these backed by long-term take-or-pay contracts. So, you know, the cash flow is going to be there when you get them done.
You know, taking up the balance sheet a little bit while staying in our three and a half to four and a half times range, I think with the right returns on those projects, which I think, you know, we have the right targets set, I think, is reasonable. The other thing I'd say is, you know, there's plenty of private capital out there for these opportunities. You know, I think that if we ever got concerned that we were going to get to a higher level than we wanted to get, you know, we could go get partners on some of these projects and still pursue the project. I think there's a lot of different ways to be able to manage it and still go after the growth projects that have the right returns.
Do you see any future opportunities for cost savings aside from the regulatory easing that you'd previously mentioned?
I think the primary place where you're going to see cost saving is on, on the regulatory front. You know, other than that, I'd say we are in expansion mode. Now, we manage headcount very tightly. And so, you know, I don't, I don't expect some big jump in terms of G& A cost and, and our, and our headcount, but, you know, there'll be some marginal cost here and there associated with these expansion projects, but we bake that all into the economics. So if, you know, we're going to need, you know, new pipeline controllers because of these new pipeline projects, that's going to be baked into the, to the project economics. So it's a, it's a cost that we're expecting to come.
You know, other than that, generally, you know, we try to hold cost at less than inflation, is what we challenge our teams to do. We go through the budget process every year to challenge them to do that. You know, especially in our products pipelines, if you can get 2% or 3% growth on the top line and you hold your cost flat because it is largely a fixed cost business, you can get some nice growth on the bottom line. You know, we manage to margin. That is an important, very important aspect of our business and especially on the products pipeline side.
Maybe in our last few minutes, what's the value proposition for owning KMI stock?
Yeah. So I think we produce very stable cash flow backed by, you know, a lot of it backed by long-term take-or-pay contracts with good creditworthy counterparties. That allows us to pay out an attractive dividend, which has, you know, we expect we'll have some modest growth to it. And then we've got a huge backlog of projects, $8.8 billion, you know, that's, you know, seven and a half of that's coming at a less than six times multiple. That other capital in terms of an initial multiple will be less than the six times because of the shape of the curve on that. But, so very attractive returns on that backlog of projects, which should drive nice growth for the company.
I think, you know, with the 22 BCF-28 BCF a day of growth, that is still coming in the natural gas space, we will have opportunities to add to that backlog for further growth.
Fantastic. With that, I thank you, Kim, for joining me. I thank you in the audience for attending.
Thank you. Thank you, Bob.