Kinder Morgan, Inc. (KMI) Earnings Call Transcript & Summary

Good afternoon, everyone. I am Jean Ann Salisbury, the Bernstein analyst for natural gas and pipelines. I'd like to introduce Steve Kean, the CEO of Kinder Morgan. Steve will take you through some slides about the company, and then we'll settle in for a fireside chat. I have some questions that I'll start out with. And then as you've probably noticed in some of the meetings that you've been in already, you can go into the Pigeonhole and put in your own questions, which I will add to the mix as well. So thanks so much for being here, Steve.

All right. Thank you. Thank you. Okay. So first, this is our forward-looking statement slide. Please review this and our SEC filings for risks that could materially affect our expected results. Okay. So this is a business we're in. We're a North American energy transportation and storage business. Our largest business -- you'll see the various contributions at the bottom of the slide. Our largest business is our natural gas business unit, transportation and storage. It's about 62% of our segment EBDA. And it's growing as global energy demand grows, and it's growing because it's a lower carbon fuel that we're moving through it. It's reliable. It helps enable the ongoing energy evolution that's going on. It can provide a backstop to renewable power as well. And also, it's growing because of the global demand. LNG facilities, primarily along the U.S. Gulf Coast, today, we serve about 50% of the transportation needs for those LNG facilities. So we have our own LNG business. It's very small. The main way we participate in this is through that, 50% of the transportation we provide to those facilities. We expect to maintain about that market share as LNG grows because where it is expected to grow is right where our energy footprint is the densest. Our second largest business is refined products. You kind of put those 2 blue lines together. That's our refined products pipeline business, along with our Terminals business, and that amounts to about 29% of our segment EBDA. And historically, that has been about gasoline, diesel and jet fuel, and it still is, but increasingly, our investments in that sector are going into handling renewable liquid fuels, like renewable diesel. We're investing in renewable feedstock midstream infrastructure. So we're not generating the feedstocks, we're not generating the renewable diesel, but we are investing in the midstream facilities that serve those as they develop. Here is how we contract for our services. So you can see the take-or-pay is the really dark green. So these are reservation fees. We get paid for the capacity, whether that's a monthly warehouse charge at a terminal or a reservation fee for a gas pipeline. And then another 25% fee base, we get to 94% when you get to what's take-or-pay, what's fee-based and what's hedged, where we do have commodity price exposure. So we have very secure cash flows and that brings to a key takeaway point. We generate an enormous amount of cash. We have grown our cash flow from operations and our CFFO less in capital investments while reducing net debt. We're BBB flat equivalent at all of the ratings agencies, and we've reduced debt and also increasing our return of value to shareholders with a growing dividend over time. So we generate an enormous amount of cash, self-fund all of our investments, have increased our cash flow from operations. And next, this shows our cash flow from operations and compares it against our dividend. So again, a very -- a lot of cash generation and a very secure and well-covered -- growing and well-covered dividend. And here, I was showing our free cash flow yield, which is on the left-hand side of this slide, is among the highest in the S&P 500. And again, that's a function of how much excess cash our assets generate and expect to continue to generate. This slide shows our budget. So you see our budget compared year-over-year to our results from last year. And also, the point on the right-hand side, this is, again, we generate enough cash to fully fund our investments, to pay our dividend. And also, we have extra capacity. At the beginning of the year, that excess amount was $890 million. We kind of called it $750 million to kind of keep the balance sheet really strong. That number has grown because we expect our results -- we were about 4% above our plan in the first quarter, and we expect our full year results to be above plan, which grows that number. Additional EBITDA grows that capacity, but we haven't quantified it yet because we're still -- there's still a lot of moving parts, as you know, in the energy business right now. So one more macro point that I want to make, and then we'll get to the Q&A. Something that I think is extremely important for investors, particularly generalist investors to understand, is the long-term need for hydrocarbons. Now we're not directly in that hydrocarbon business in terms of producing it, except in a small way in our CO2 business. We provide the midstream infrastructure that moves and stores it and that demand will continue to increase, we believe, particularly in natural gas. And you see different energy sources, different growth trajectories, but pretty much everything except coal is up and to the right and that's because there'll be additional energy demand across the world really that cannot be met entirely with renewables. And so our assets are going to be around for a long time to come. We're making a gradual pivot, as I mentioned, to the energy transition, the energy fuels of the future. We can use our existing assets to serve that as well, and in the meantime, we're generating a lot of cash from these assets, and we'll continue, too, as time goes on. And that extra cash gives us option value in terms of whether we further strengthen the balance sheet, whether we repurchase shares, increase the dividend or continue to invest in projects. And as you saw from the budget slide, we're doing all of those things, and we have capacity left to do more. So that's the summary. Thank you.

Great. And again, I have some questions to start, but if people want to submit their own, I have the Pigeonhole here. Great. Looks like someone just -- people are submitting questions. Great. Okay. It's now working. Great. So as you mentioned, Kinder Morgan has stable cash flow with a base business that's growing, how are you thinking about capital allocation or free cash flow from here?

Yes. So we think of it in several orders of priority. First is, get the balance sheet strong, and we've gotten there. So at 4.5x debt-to-EBITDA level with our stable contract structure and our stable and secure cash flows, that's a BBB flat credit rating, and we're in good shape there. And so then after that, it's a function of what are the available capital investment opportunities that provide good NPVs well above our cost of capital and add value to the firm. And so historically, that's been $2 billion to $3 billion for a number of reasons. That's more like $1 billion to $2 billion. As we see this year, our budget was $1.3 billion. We'll probably be more like -- looking more like $1.4 billion, $1.5 billion right now. But anyway, so you exhaust those opportunities, those add to the value of the firm. And then from there, it's returning value to shareholders. We have a good dividend. It's a growing dividend. It's well covered. And then the more flexible return of value to shareholders opportunity is share repurchases. And so we have the capacity to do share repurchases. And then the other thing that enters into the thinking a little bit is, it's good to have balance sheet strength because if you build that strength, it doesn't go away. You have the -- we're at 4.3 in our budget, so a little better than our 4.5. You end up at 4.2 or whatever, it doesn't go away, it's there to create the opportunity to take advantage of opportunities going forward. So we're kind of in -- that's where more of the judgment enters in. Buy more shares or keep a little balance sheet -- firepower for future opportunities.

Great. Your 1Q results came in 4% ahead of your original budget due to both operational performance and commodity price. Do you see that carrying through for the full year? Can you talk about tailwinds and headwinds for the year?

Yes. So we haven't quantified what we think the full year outperformance will be, but it was, as you said, 4% in the first quarter. And we feel based on what we could see out there that we're going to be above our plan for the year, but we didn't quantify it in April because April is early, and there's still work to be done, et cetera. But the commodity price is a bit of a tailwind. We're not as directly exposed to that, but in our gathering and processing business, which is 8% or 9% of our segment EBDA, there's a little bit of indirect exposure there. We do have in our ERR business some exposure. That's been a tailwind. Headwinds have been costs. We've really done a good job on controlling inflation, but we've had some additional work that we've scheduled ourselves to do on the maintenance front this year, and that's a bit of a headwind. We're forecasting a little inflation more than we've experienced so far, which is, I mean, good. But that's a bit of a headwind as well. Other tailwinds. On our gas pipeline assets, we're doing better on G&P. We're doing better on our Texas Intrastate business. We're doing better on Tennessee Gas Pipeline and the Stagecoach acquisition. We're ahead of our acquisition model on that. That's -- those are all tailwinds contributing to our business.

Great. And you mentioned the cost inflation. Can you just talk a little bit about how much of that you can pass through, if you are mainly protected?

Yes. So we've got about 25% of our revenues have inflation adjusters in them. Otherwise, it's a matter of addressing any cost increases when a contract comes up for renewal or whatever. Now we don't have and -- because we're a very capital-intensive business, the assets are all already there. They've been built. They've been installed. They're not subject to inflation pressures. Where we're subject to, it is on -- our operating margin runs between 60% and 70%, depending on where the asset is. And so on about 25% of that -- the revenue going into that operating margin calculation, we have escalators. And then on that 30% or so, 30% to 40% of the OpEx or the cost piece of that, we have succeeded in holding inflation largely at bay. And so the escalators should -- we should come out ahead on that so long as we can keep those costs at bay.

Great. Excellent. Well, we can start jumping into more assets now. I see we have several here about the Permian, not shocking. For any generalists in the room, the Permian is where most oil and gas growth are expected over the next couple of years, and we are running out of gas pipeline takeaway. So the question here is, how is the FID process progressing for the PHP and GCX compression expansions?

Okay. So we built the PHP. Those were -- PHP and GCX 2 Bcf apiece pipelines. We've built those recently. And now with the Permian bottlenecking up again, the question is, can we expand those further? And the answer is, we can. We can expand them by adding compression. The thing about compression expansions is, they are -- they're easier to execute and faster to execute. And so we think we can get PHP in October of '23, which allows a nice backstop or a nice relief for the capacity constraint and then GCX within a couple of months after that. So when we launched the open season of PHP, we had an anchor shipper who took down half the space, and so we're trying to fill up the balance of that space. And then GCX, we launched a couple of weeks after that, and we're in commercial contract discussions with a number of potential shippers. And so I'd say, the commercial discussions are going well. We haven't reached FID because we FID -- unlike some others who have come out and with different risk profiles, perhaps, but we FID when we have contracted assets under long-term contracts with creditworthy counterparties or when we can see them -- GCX, we were a little bit earlier than that, but we saw it with -- and in 2 months, we had it filled. So I mean we're going to be very disciplined about that. So compression expansions are faster. They are higher fuel rates, okay, but they are less land intensive. So there's less landowner issues to deal with. They're less permit intensive, so you don't have Nationwide 12, the Army Corps permitting to deal with. The emissions can be permitted by rule under TCQ. So we don't need anything special there. And so it's much easier to get those things, much more reliable to get them executed and done. And so we feel good about our prospects on getting something done there. And if you look at -- to your point at the start, I mean, the Permian needs a new pipeline every 2 or 3 years. I mean it just continues to grow. If it grows as expected and it's just a projection, but it is going to go from a point of being bottlenecked like it is now, and that will get worse, and then it'll get debottlenecked, and then it'll get bottlenecked again, and then it'll get debottlenecked. And so there's room for nearly all of these announced projects. It's a question of time, I think.

And then another one on this, given ever apparent Permian growth and gas constraints, how soon would you look to commercialize on Permian Pass? And I'm adding this part. Can you comment at all about -- I think people were quite surprised that Matterhorn moved forward. So anything you can comment about them?

I won't speak for them, but -- and they've been clear about this. It's not fully under contract, and that's their choice, and they'll work to get it under contract. But I do think if that or energy transfer or something like that happens, I think we'll do between us and Whistler, and we'll probably push out the need for Permian Pass. So we did GCX in 24 months from FID to -- this is greenfield now. So FID to in-service is '24. PHP was '27. We don't see it getting shorter than that. And so we were thinking about Permian Pass is '30 and that would be '24 -- late '24 or '25. That might be a year or 2 later than that now.

Okay. That makes sense. And then one more on this topic. As your Texas Intrastate system hits full capacity, are there opportunities for down market expansions?

Yes, and we've done some of those. And so that's an extremely important point. There's a lot of gas coming from the Permian to the Gulf Coast, and that's outside of a FERC 7(c) process. That's really the Army Corps and it's relatively -- it's easier and faster. As all that gas gets here, it needs to go someplace. And so a lot of it is going to go to LNG facilities. Some of it's going to go to Mexico, but it also needs to go to industrial facilities, power plants, petchems, into the interstate market, which we can access from our intrastate system. So the more that gas comes, the more it fills up the system that we have that is that last mile connectivity to all those things and the interconnect connectivity to the interstate market and to LNG. And so we have been debottlenecking that system. We did 2, what we call, crossover expansions. So those were a couple of hundred million dollars apiece, and that was about debottlenecking where GCX and PHP were arriving as they hit our system and getting them to those end-use markets. And so it's relatively -- it is capital efficient expansions of that existing grid in order to be able to get all that gas out. We are out in the market right now, marketing a storage expansion, which is -- has been proven to be increasingly -- of increasing importance and value on that system to help serve the power generation market in Texas. And so there are those kinds of opportunities to expand.

Great. So staying on gas pipelines, how is FERC regulation impacting your pipeline business? Are you still able to expand your interstate systems for new gas supply and demand in a timely fashion?

Yes. So there's been a pretty dramatic turnaround, one of the most dramatic turnarounds I've seen, in policy. And the first move was to put in place a new certificate policy statement, which was -- had been in draft form and was under discussion for a long time. It would update one that was done in the late '90s. And then because of the ambiguity and uncertainty, I think the commission thought they were adding certainty, but it became clear from the response that it was not. And what the market needed and particularly in the current environment where we're trying to help our allies and everything else, we really needed more certainty. And so they put those -- that certificate policy statement on draft status and went back to what we were using before. And then they started processing certificate applications. We had 2 pending, and both of them came through within the next couple of commission meetings after that and others as well, other third parties. We've got another one we're in the prefiling process on to serve TVA. And so they've been moving these things. They've been moving these things. Now the wild -- the ambiguity -- and what they were really trying to address is that the Court of Appeals has been pretty clear. You've got to somehow deal with greenhouse gases here when you authorize these facilities. And the old policy statement, of course, didn't have anything to do with that. And so they were finding -- trying to find a way to do that. And so where we find ourselves now is, we put all the greenhouse gas information in the record because when it gets to the Court of Appeals, we want the certificate to stand. So we operate within the old certificate policy, but we do extra to make sure that we survive on appeal, right?

Yes. Great. So moving over to LNG. For a world that is increasingly desperate for U.S. natural gas, is Gulf LNG liquefaction an option? Is there potential for significant expansion? [ Can I guess this is ] Elba?

Yes. As I said during the overview, most of the way we're participating in LNG and the growth opportunity there is in providing the transportation services to our customers, and that's a very -- we like that. It's low risk. It's good returns. Long-term contracts. A lot of it is very, very capital efficient because we're expanding off of our existing grid. So that's all good, and that's a very nice way for us to participate in that market without taking global commodity market risk, et cetera. We do have 2 LNG facilities. Both were originally regas facilities, one still is, that's Gulf LNG. We have a customer there. That customer's contract runs until 2031. And so to -- in order to convert that into an LNG opportunity, which is worth talking about, particularly in today's environment, it is worth talking about. We have to work things out with that customer consortium. And so we'll do our work there. The Elba facility is under contract to Shell, and there is some -- but it's a small facility, 350,000 MMBtu a day, not millions of tonnes per annum. And so it's a smaller facility, but that does have some expansion capability. But the facilities are under contract to Shell, which we like. That's a 20-year contract. And we'll work with them to see if there's an expansion opportunity there. But the bigger bang for us is providing the upstream transportation services to these facilities. And again, as that demand grows, we expect to continue to serve around 50% of it as it grows because of where it is in our footprint.

Great. You have several rate cases coming up. Can you talk about the expected timing of when these would affect EBITDA and if there's any past examples that you would kind of point investors to, to gauge impact?

Yes. So we have -- so there are rate cases where we had an obligation to file. Then there are systems on which we were just updating our cost of service and then there are systems with no comeback or no obligation to come in and file a rate case. So the ones that were in line for this year were Colorado Interstate Gas and Wyoming Interstate Gas. We have a settlement there. We filed it. We're waiting on commission approval. We have some cost and revenue studies where we have been in conversations with customers. And then we have a Section 5 action against EPNG, which we think is, and we've said on rehearing, really ill-founded. I mean this is one of the most competitive pipelines serving one of the most competitive markets. It really doesn't make sense to say, oh, there's a franchise here, and we need the cost of service regulate you. It's really unnecessary. And so our approach to these things is, we try to stay away from that process. We try to keep our customers happy. And we try to get as much of our business as we can on non-max tariff rates, which is what gets adjusted when you go through a rate case. And so across our system, we have roughly 30% of our gas -- interstate gas pipeline revenues that are at max rate. And so if there were a tariff adjustment, it would affect those. The rest are discounted rates because of the competitive market or the negotiated rates because we entered into an agreement with a customer at arm's length. We did an expansion for them or something else, since they move outside of that process. So our approach is to treat this like a business, not like we have a franchise, and treat our customers right and do business the right way and to -- if we're in a rate case, to settle it and move on. And that's how we've approached it, and we've done that historically on NGPL. FGT, which we don't operate, but we own 50% of. They just resolved the rate case. And so when we find ourselves in them, we look to resolve them on attractive terms. We give our customer services beyond what we're really obligated to give them, and those things can be at risk if you're in a rate case. And so we just try to work things out. Give value, get value.

Great. So one on Jones Act here. Given shipping tightness, are you seeing any rebound in Jones Act tanker rates or your costs going up as well so it doesn't really impact EBITDA?

No to the last. So the costs aren't going up enough to offset the benefit we're seeing in the uptick that we've had in the Jones Act vessels. And so we saw a meaningful uptick starting in the year, but also -- unfortunately, right after the Russian-Ukraine conflict because there were certain products moving to the East Coast that were either Russian or Russian by displacement because it was Europe, let's say. And so getting crude up to -- around the horn and up to the Mid-Atlantic or Northeast and getting refined products or blend stocks out there, those kinds of things made sense to do. But the other phenomenon, I think, is that when oil prices went negative a couple of years ago and people were scrambling, one of the things that they were doing was cutting every cost they could, including cutting their midstream infrastructure commitments, including Jones Act, okay? Well, we think they overcut, and so some of it is really just people coming back and getting back tankers they had before. And so in terms of where we are pre-pandemic, 60,000 to 65,000 was daily charter rate, and we are now nudging up to the bottom of that range. And so coming back, but -- so we're above plan on that business this year. We're still lower year-over-year because we had some much higher charter rates from earlier years that rolled off, okay? But in terms of where we're going from here, it's definitely ticked up and looking better in terms of charter rates.

Great. So now moving over to some of your renewables businesses. I have a question about the voluntary RNG market. How do you think about sizing that market? And do you find that customers are kind of just looking at all of these options, and they're just -- they're looking at ways they could reduce the carbon footprint, but it kind of specifically comes down to their cheapest way? Or are these people that specifically want R&D?

It's the latter or the regulators want them to, right? And so the -- so the 2 markets for renewable natural gas are, it was part of a 20-year ago effort. We're addicted to oil. We need to find another way, get switch graphs. You may remember some of these terms. We were going to get all kinds of things into the transportation fuel stream. Ethanol, we have ethanol requirements, et cetera. Well, one of the things that's in there is the cellulosic and RNG, which is really landfill gas that has to be captured under the Clean Air Act. It can either be burned, can be used to generate power or it can be used in the gas stream. It's extremely lucrative to use it in the transportation stream. And so that -- you have 11.7 RINs, renewable identification numbers, per MMBtu of gas and the RINs are trading at over $3. So that's getting close to $40 per MMBtu for that. And so that's going to be -- and we think it's volatile, but it is -- it's underpinned by good policy rationale, and it's a relatively small piece of the market. There's no competition with fuel -- or with food rather between ethanol in fuel use or food use, but -- so that's that. It's a very lucrative market, but it is subject to some volatility. The voluntary market is people who are trying to reduce their carbon footprint, who see compressed natural gas from renewable natural gas as part of the key to that. So we talk to and serve people like UPS, okay? Amazon, maybe the USPS, but other -- and small manufacturing who don't have natural gas as a big piece of their cost structure. And so -- that they've got a retail brand, and so they want to be -- to meet their net-zero targets, they need that in there. And so we think the voluntary market is actually increased. It's not heavily transacted, a handful of deals so far, but the price is moving up. We think it's moving up north of $20 an M. And so what we'll look to do is have some part of that stream that we just put to bed under a voluntary contract that's fixed price, and it's for 20 years, and then we'll still have a piece that's higher valued, frankly, or we'll look for ways to share that value with someone, those sorts of things. But we're getting good returns on those investments. We've got one running. We've got 3 more we're adding and others that are under development. And these are $25 million to $40 million at a pop and good returns. And so the bigger underlying point there is that we are pivoting toward renewables, but we're doing it in a way that's very responsible for our investors. We're actually doing better in our returns. Some are projected returns. But we're doing better in those than we are in our bread-and-butter midstream investments. So making the pivot, but doing it in a way that's responsible to our investors, not loss-leading, et cetera. So we participate in our existing business and in the new ones we're being disciplined about how we proceed.

Great. So now kind of staying on renewables, a few about the carbon sequestration business. There's, obviously, a lot of enthusiasm and momentum around this a year ago and then kind of Build Back Better fizzled. It seems like the enthusiasm also fizzled. Is it fair to say that until there's clarity on the 45Q, you're probably not going to see a lot of movement on people signing up for...

I think that's broadly a fair statement. I mean because there are things that are economic today under the existing 45Q structure, the $35 and $50, $35 for EOR, $50 for sequestration, and it's things like processing plants, ethanol plants located near CO2 infrastructure, which I'll come back to in a minute, those will work. Well, we were having really good discussions about that and then Build Back Better came along. And I'm not blaming on Build Back Better, it's just that everybody thought, oh, this is going to get a lot better now in terms of the subsidy and so things cooled. They're back on and there's still some talk that there will be not a Build Back Better like it was conceived, but that there will be a renewable focused thing. And so long as there are adequate deficit reduction and all that, you could get a 45Q deal as part of that, and that will help a lot. That will definitely help a lot because that will open up more opportunities. Right now, we've got about -- but let me talk about the CO2 pipeline network because this is an important point to understand. You can't just repurpose existing oil and gas pipe to move this stuff or at least not to move it efficiently. We move in our CO2 network, which we use for enhanced oil recovery. We move it at 2,000 psi. The most of the transportation network in the United States is 600 to 1,440 for the new stuff. And so you can move small amounts for short distances and make it work, but generally speaking, you need purpose-built pipe to do this. And that's -- it could be overcome, but that's an obstacle that people I don't think fully accounted. And so we need some clarity there. We also need clarity on the injection permitting. Title VI. There are only 3 Titles VI permits. They all took 5 years or so to get. We're working in Texas right now on a Title II permit, which is under Texas jurisdiction, which would be for sequestration. You put it in the ground and a water disposal well or something that you keep it there, and so that's something that we're working on. But these things -- this is going to happen, I think, and it will happen at least a little at first, but it happens a lot more, obviously, when you build new CO2 infrastructure and you get -- and you don't get that until you get a clear line of sight on what the credit is going to be and is it going to be a refundable tax credit, things like that.

Great. And just to build on that because you touched on this a little bit, but can you talk a little bit more about -- assuming that eventually, a 45 credit, this figure does come through, can you kind of talk about how you would -- how KMI would address the opportunity? And what competitive advantages do you think that KMI has? I know you have the existing CO2 pipeline, but EOR versus brand-new sequestration timing-wise, cost-wise?

It's the existing network. It's knowing how to build new ones and operate new ones where that infrastructure gets built, and it's also the underground expertise. And so for decades now, our geophysicists have figured out, how do you put this stuff in the ground and get oil out? Or how do you put it in the ground and keep it there? And so that expertise gives us a little bit of a lead. I don't want to overplay it because everybody has -- a lot of people have geophysicists, but knowing how to have practically done that and seen the difference between projection and reality and worked your way to a point where you've got some expertise, it is a moat, a bit of a barrier for us.

Great. And basically, it would just be as simple if you were putting it into your EOR -- not as simple, technically not simple at all, but you would kind of stop taking the CO2 from Colorado area and you would start using CO2 in your existing CO2.

It could be as simple as that. Now we have space for both right now in our pipe. And so the 300,000 Mcf that is within 30 miles of our pipe, its processing facilities, you can get to 1.5 Bcf, but you've got to count power plants that aren't there without bigger subsidies. But there's room to put that in and move the geologic CO2 as well. But as that grows, yes, you can just use the same infrastructure for the new source.

Great. And it is like shorter to get -- like a lot shorter to get permits for EOR CO2 than sort of brand-new sequestration, I think.

Yes. And also some of it is just already permitted. So you're just building out the development.

Great. So gas price has obviously been a very hot topic.

But let me clarify. To have it get credit for 45Q or something, you really do have to have like a Title VI or Title II permit or something. You have to go through the process.

Okay.

I believe that's right. Yes.

Can't just [indiscernible].

Yes, I think that's right.

Okay. Great. So gas price has obviously been a hot topic. It's kind of doubled in the last couple of months. Do you have an internal view on gas price from here?

We wouldn't have projected this, and again, we're not in the commodity, we're in the midstream infrastructure, but it matters. It matters to how active our producers get, et cetera. And so we certainly develop a view, and we compare that to NYMEX, and we compare it to other people's projections. And I think this is well above, and it's -- a lot of it is geopolitical and a lot of it is producer discipline, which has been talked about a lot. And I think eventually, the returns are there, and they're there in such a big way that we have efficient capital markets. You've already seen private capital take on more of the product -- take on more of the rigs and generate more of the opportunity there. But I think it's that combination of things, additional demand, people wanting to get off Russian gas. There hasn't indirect effects -- unexpected indirect effects like coal demand has gone up. And so there was a price point at which power producers would switch from gas back to coal and that has been elusive. That has moved away. And so power demand for gas has stayed high. So it is demand and supply like all these things are. There are plenty of producers. There's plenty of consumers. This isn't something extraordinary. This is market dynamics at work, but those market dynamics have been influenced by those 3 or 4 factors.

Yes, that makes sense. And you kind of touched on coal. International coal prices are actually even higher than U.S. coal prices. I think back in the day, Kinder Morgan did use to export a reasonable amount of coal. Is that something that could kind of grow and could it be material to EBITDA?

Yes, it's a small part of our business. It's part of our bulk Terminals business, which is about 20% of our Terminals business. So if you look just on a Terminals level, we're above plan there because there's been a lot of extra movement beyond even what we anticipated in the plan, and it's export driven. So we have a facility in Houston. We have one in the New Orleans area and one on the coast of Virginia. And so those have been moving a lot more coal than expected. But to put it in context, that has moved it up to be about 5% of our Terminals, segment EBDA, which is 13%. So that's the order of magnitude. It's relatively small.

Okay. But you could grow it. There's more [indiscernible] grow.

Yes, there's a little -- there's room to grow. Yes.

Great. Can you discuss how volumes are trending on your Haynesville system and any opportunities for expansions from the Haynesville to the Gulf?

Yes. So volumes -- we have a significant Haynesville gas-gathering position where we gather and process the gas. We don't extract liquids. It's a dry gas play, but we purify it. And then it goes into third-party takeaway pipelines. And we've looked at expanding our -- building one of those takeaway pipelines, and we've still got something on the drawing board. Others are moving forward with some. And the LNG operators are building their own or having them built for them. So there's going to be, I think, good takeaway capacity. And when it fills back up, we may participate in that. In the meantime, on Haynesville, we're up dramatically year-over-year because the volumes are coming up, and we've got a lot of space on that system as it is today. And so it's not capital investment free, but it is very efficient capital investment, much more so than you see in a typical gathering asset because we have that installed infrastructure that's not full. And so it's moving up, the EBDA is moving up, and we're not having to put a lot of steel in the ground to get that to happen.

Great. So I'll read this question. So the question is, at what point do you believe you will reach full capacity on GCX and PHP? I think they might mean on like the existing capacity, but I think you're probably pretty close to full capacity in [indiscernible]. When do you think the Permian [ onset ] of gas takeaway is my reinterpretation...

Yes, maybe [indiscernible]. So then again, yes, if you believe the projections on the Permian and there's underlying fundamentals that support those projections with all of the stuff that comes out of the Permian, oil, NGLs and the gas that's associated with it, gas is sometimes just along for the ride. I don't -- I think that's less true now because gas is as valuable as it is. But the richness of that basin, there's reason to believe that it continues up and to the right. And to the extent it does and we continue moving up our LNG exports, et cetera, then they're going to keep needing additional new debottlenecking infrastructure projects. And so it's kind of full right now. Our GCX and PHP systems are full. We sometimes can squeeze out an extra 10 on ambient capacity. Just conditions are such we can sell an incremental 10. And so we -- this is 10,000 a day on 2 billion cubic feet system. So they're really -- this is -- they're pretty full.

Great. And then one on the refined products system. It seems like -- I was just complaining to Peter that I bought a very expensive plane ticket to Houston. I think everyone's kind of noticing the jet fuel, the diesel prices. So it seems like one reason for that is that refinery capacity hasn't really come back as much as perhaps people thought. Is that weighing in on your projections for your refined products business?

That is not because I think the refineries are running pretty full out. They're running 91%. They're not at their peak of, call it, 95%, but they're running pretty flat out. A couple of things have happened. One is -- and not necessarily connected to us, I'm trying to think. There were 1 million barrels that were of capacity retired during the pandemic, okay? There are 2 million globally. So you've got less refined capacity. And that's a big part of the explanation for your plane ticket. And for the price you see at the pump right now is that we're maxed out on refining capacity. So you can release from the SPR all you want. We're still maxed out on what we can convert into what people are really looking for. Now we haven't -- the thing we've been watching very closely is, when does demand destruction happen. In 2007, the price marched up and then it got to $4 and that was like a magic number and all of a sudden, people started -- it didn't come down dramatically because it's very inelastic. The demand is extremely inelastic and so it came down a few percentage points or something. And we haven't seen that for sure yet. I mean we've seen that we're running a little under what we had planned for the year, which was about 2% below 2019. So almost back to 2019 levels, a little below that, but it's hard to know whether that's just noise or whether that's actual demand destruction. I haven't seen enough evidence yet to call it.

Yes. Well, I still bought my ticket.

You still bought your ticket?

I'll probably buy another one.

You did destroy the demand.

So it seems that the road map for the energy transition is now looking longer than maybe investors thought a few years ago, particularly for natural gas. Do you feel like the terminal value for natural gas or even you can just go broader to traditional hydrocarbons is considered higher for like -- has been pushed out in the future...

I think it has. And there are a number of things. There's -- I would say that people -- there's the opportunity to get confused when you compare targets with technologies. Like what -- we actually have the capability to do. And so you look at things like, oh, we're going to be net zero in this or that, in 2050 or 2040 or 2060 or whatever. And then when you look at what's actually required to make that happen and you conclude that it won't work with the technologies we have today. Now that doesn't mean you throw in the towel, but what it does mean is, don't pretend like and don't behave like and don't value companies like this is all going to be over. It's not. And what really needs to happen is, there needs to be a massive amount of R&D and there needs to be other strategies besides just using windmills and solar panels and batteries. The technology is just not there. And so I think that energy reality is coming more home to roost, and it's coming home to roost in some very practical ways, which will hopefully get people to a more honest discussion about what will and won't happen, and what's required to make some other objective come true and what role, really, how long is the transition going to be and what's required there. And so that's important. And I think -- look, I mean look back to where the whole sector was trading in 2015, it was 14 to 16x enterprise value to EBITDA and now it's 8 to 10. Okay. Well, some of that for sure is that -- that was the height of the shale, okay? And so some of that is real, but I think there's some part of that, that people were anticipating the demise of what we do much sooner than the practical reality will really show you and ignoring the ability of us to use the stuff we use today, particularly in midstream, to use the machinery and everything that we use today to pivot to that transition. So our whole approach to this has been, be good at ESG. We're in the hydrocarbon business. We transported for others, but still, we're in that business. Be good at ESG. We're very highly ranked in ESG. If you pick up the presentation, look at Page 41, we worked very hard for that. It is important to be good at that. But then also, recognize what's going on, position ourselves. We market our services in California as deliverability. The more you take baseload out and rely on intermittent, the more you need to call on our capacity, which is what the real value to us is. The reservation charge that you pay to have it when you need it, right? That demand actually goes up. So there's that. There's using renewable diesel in our facilities. There's looking at hydrogen, but that's long, long term, I think. There's looking at repositioning our CO2 business. There's a sequestration business. Although we got a lot of hands to play and a lot of options to execute on over a decade's long period. In the meantime, we gradually pivot the ship because we've got time to gradually pivot the ship to more renewable natural gas and other things. And so we generate a lot of cash. We invest in a very disciplined way. We find ways to return that cash to shareholders while covering all of our attractive return on investments. We maintain a strong balance sheet. We're thinking hard about the long term and positioning ourselves for it, but we're going to be here for a long time, doing what we do today plus some new stuff.

Great. Yes. Actually, I thought that, that slide that you had, it might have been a year or 2 ago now, but it was showing that the intermittency of the day in California caused you -- your peak demand -- even in a very high renewable scenario, your peak demand for gas in a day was kind of the same as your peak demand now. And so you don't need as much gas over time, but your peak remains the same. And I think that was a real [indiscernible] pipeline.

Yes. And it's actually higher when you think about the baseload has been taken out and the gas is there, and they're now adding some gas capacity, but that's all that's relied on. So -- for dispatchable, almost exclusively. You can dispatch hydro, but it's a limited resource. But yes, that is an important insight. It's not about how many molecules, it's about how much people need our capacity when they need it.

Yes. I thought that was a great slide. Great. Well, I think we have one minute left. So if you just want to close with any last-minute thoughts of how you want people to -- like the top 3 things that you want people to think about Kinder Morgan?

Yes. So I've said them already, but I'll repeat them. I mean think about the long-term lifetime of our business; think about the value of natural gas, which is our biggest business, in serving global energy needs that are growing and the export role that the U.S. has to play in that as well as the role of natural gas in any really rational energy transition. We should be displacing coal and then new coal builds around the world. We did that in the United States, and our greenhouse gas emissions went down from 2007 to current, okay, while we grew the economy and while we grew our power generation, et cetera, and a lot of that was natural gas. So think about the real lifetime, real runway of this business. And we take care of your money. We invest it wisely and carefully. We don't spend it unnecessarily. We invest at attractive returns. We generate a lot of cash, and we look for ways to give it back to you. And so I think we're a very disciplined company. I think we've been very thoughtful about the future, while getting -- while being realistic about what we can work on and the assets that we have today.

Great. Well, thank you so much, Steve, for joining us and thank you, everyone, for joining us as well.