Good morning, and welcome. I'm Richard Kinder, Executive Chairman of Kinder Morgan. As usual, we look forward to this event to explain the Kinder Morgan story in a detailed, and I hope, transparent way. We hope you come away from this morning's activities with a realistic view of what we look at as a very positive story for Kinder Morgan and its assets. Now, we can't have any of these presentations without, of course, telling you that it should be obvious to anyone that we will be making forward-looking statements, of course, and this is the warning to take it all with a grain of salt. We think everything we're saying is very accurate and very perceptive, obviously, but then we're prejudiced. Moving on, what I thought I would try to do today...
Last year, I remember I talked about the overall market for the kind of assets that Kinder Morgan has, and specifically, the growth of commodities, the important role of natural gas in any reasonable story for the future of energy. Today, I'd like to try to look at Kinder Morgan as a third party might look at it in terms of would you invest in this stock, and is it properly valued? I think you have to start by looking at energy infrastructure in general. We believe that energy infrastructure, particularly natural gas pipelines and storage, really has a very long-term runway in front of it in terms of moving and storing the energy not just of today, but of tomorrow. Where does Kinder Morgan fit into all that?
Most of you know this story, let me just repeat a few facts for you. We're the largest natural gas transmission network in the United States. We have about 70,000 mi of pipeline. We move about 40% of all the natural gas consumed in the United States. Very importantly, and I think recent events have demonstrated this, very importantly, we have about 700 BCF of natural gas storage. That's the largest storage position in America and about 15% of the total U.S. natural gas storage. Beyond natural gas, we also have our other segments, which are important contributors to the bottom line. We're the largest independent transporter of refined products in America. We move about 1.7 million barrels a day. We have about 10,000 mi of refined products and crude pipelines. We're the largest independent terminal operator in America.
We have 140 terminals. We have 16 Jones Act vessels. We're the largest CO2 transporter in America. We have the capacity to move about one point five BCF a day of CO2. We produce it in the southwest Colorado region. We move it across New Mexico and move it into the Permian Basin, where it's used for tertiary recovery. Importantly, we think in the future, some of it, and we have one project now, some of it will be used, will actually be sequestered in wells in the Permian Basin and not used for tertiary recovery. Finally, we have a growing energy transition portfolio. Most of you, I think, recognize the forays we made into renewable natural gas, which we think has a bright future.
When we complete the build-out of the facilities we've acquired, we'll have the capability to produce about seven BCF of renewable natural gas beginning in 2024. We're also involved in renewable diesel, both on the West Coast and the Mississippi River area. We're beginning to take a position in carbon sequestration, and we've announced our first, albeit fairly small, project in that area, just as recently as last week. If you look at the overall mix of Kinder Morgan's EBITDA, as you can see, natural gas contributes almost two-thirds of our segment EBITDA. The rest of the EBITDA is split pretty equally between our products, terminals, and CO2 segment. When I invest, I always like to participate with somebody who has skin in the game.
I'd like to have a management team or a co-investor who is looking at the investment the same way I am as a passive investor. I think if you look at Kinder Morgan through that lens, it's pretty interesting. First of all, we have 13% of the company owned by the management and the board. That's a significant portion of the company. We have maybe more importantly, a great core part of our executive compensation paid in stock. In fact, as this slide demonstrates, 68% of executive compensation is delivered in restricted stock. I think that leads us to a really great amount of discipline in how we approach our business. We strive to be a low-cost operator while of course maintaining safe and reliable operations. We have a very high return criteria that we look at.
We run all our investments through that criteria. We internally fund our dividend and our CapEx, we work to return excess cash flow to our shareholders through dividends and stock repurchases. I guess the real test, which you see on the right-hand part of this slide, is what have we returned to our shareholders over the past several years. You can see the left-hand portion or the gray area of that slide, we've generated about $34.5 billion since 2016 in cash flow from operations. We've also disposed of certain assets that we believe were not core to Kinder Morgan, we've raised a little over $10 billion from that source. What have we done with that money? We've spent about $14.5 billion in dividends paid and stock repurchased.
We've used about $8.5 billion for debt reduction, and we've invested between $16.5 billion-$17 billion in projects and acquisitions at what we believe and what has proved out to be very attractive returns. If you look at that, we have a stock value of just north of $40 billion. We've returned about 36% of that market value to shareholders since 2016 through the payment of dividends and the repurchase of shares. Now we know that our shareholders have a wide range of opportunities and investment alternatives. How does energy infrastructure in general, and Kinder Morgan significantly, compare to those alternatives? This slide seven sort of demonstrates that.
If you look at some of the things that we think are important for an investor to look at, we think we score pretty well, and the whole energy infrastructure does. We have long live tangible assets. We have customer contracts extending for several years. We believe we support a key part of the economy, not just in the United States, but around the world, as the demand for LNG in both Asia and Europe in the last year has certainly shown. The last two check marks on this sheet, I think, are particularly important. There are high barriers to entry into our business. It's not just from the standpoint of having the capital to invest, but unfortunately, in my view, the regulatory hurdles are enormous today in investing in new facilities in energy infrastructure.
That's a bad thing for the economy in general, I think, but it's good for a company like Kinder Morgan, where you have 80,000 mi of pipeline and all these other assets that are simply irreplaceable in today's regulatory permitting environment. Finally, the last check mark, I think, is also beneficial for an investor who's looking at energy infrastructure and Kinder Morgan, and that is a significant cash flow returned to investors through dividends. I'll show you a slide on that in just a minute. I think increasingly, the market in these kind of volatile times is beginning to realize that assets that generate real cash flow will outperform more speculative investments.
This was just a snapshot of one year, but as you can see where the Alerian Midstream Index turned out, compared to more speculative investments, and it's quite a difference in 2022. This is a trend that we think will continue as we move forward in what I suspect will continue to be volatile times in the broader stock market. Let me talk about dividends and returning value to shareholders. We believe that a dividend, and the market has reinforced this view, is part of the return provided to all investors. In fact, if you look back over the last century since we've been keeping statistics on this, the dividend has been an important part of the total return that investors get, whether they're investing in specific stocks or the S&P 500 or some other general index.
Over the last 10 years in a bullish market, over 25% of the return in the S&P 500 has been from dividends. If you look at this slide eight or slide nine you can see today's energy segment of the S&P 500 is by far the best dividend yield at a little over 4%, better than any of the other segments. We think this has real value on a going-forward basis. If you look at Kinder Morgan specifically and the chart on the right-hand part of this slide, as you can see, we're one of the top 10 dividend payers in terms of yield in the S&P 500. This is not a flash in the pan situation.
We've been paying dividends for 25 years. 2023 marks the sixth consecutive year we've increased our dividend. We expect to continue to be able to make modest increases in that dividend in the coming years beyond 2023. To sum it up, why should Kinder Morgan be a core holding for any investor, whether energy-specific or a generalist investor? We think there are several significant advantages that we bring to the table. The first is we happen to be the largest energy infrastructure in the S&P 500. We think size really does matter in terms of long-term outlook and in terms of long-term capability of delivering value to our shareholders. As I've said, we have a highly aligned management with significant equity interest in the company.
We're able to continue to grow our EBITDA between 2022 and 2023. Coming off a very good 2022, we're projecting another $200 million increase in EBITDA year-over-year. We have a nice dividend yield. We raised it again this year by a modest 2%. We have a share buyback program, which our board recently increased, so we now have $3 billion of buyback authority, of which about $2.1 billion remains untapped. For all these reasons, we think Kinder Morgan brings a lot of positives to the table. We look forward to telling you our story this morning. With that, I'll turn it over to Steve.
All right. Thank you, Richard. Continuing on the theme here, I'm gonna talk about outlook, and that's the outlook for our sector and also the outlook specifically for our company. Kim is gonna get into depth on all the business units, every one of them, talk about the commercial and operating and financial strategy there. David is gonna give you our financial philosophy. He'll review our capital allocation principles. He'll repeat our capital allocation principles, talk about our key performance metrics, and then take you through the 2023 budget, which takes all of this that we're talking about, how we're executing and how we're running our businesses, and takes it down to a set of numbers for the year that we will be tracking and updating you on as we go.
At the end, we'll have a Q&A session with our business unit presidents, who are all here, as well as our key staff organization heads. You're gonna have an opportunity to hear directly from them during the Q&A as well as at lunch. Okay. Everything starts with vision and mission and values, doing our business the right way. This ties into the large overall theme here, which is that affordable and reliable energy is essential to human development, and it's gonna be needed for a very long time to come, which means that our assets are gonna be needed for a very long time to come.
As one of the obvious truths about energy, but one that's not covered very much, is that energy is absolutely essential to pulling people around the world out of poverty, giving us all an opportunity at a meaningful life. The ability to get around, a strong economy, the food we eat, the shelter, the clothing that we wear, et cetera, all require energy and hydrocarbons specifically. You know, something that is not often focused on, a little under 20% of hydrocarbons goes into the four main pillars of a modern society: cement, steel, fertilizer, and plastics. The things that you need to build a modern society that increasingly are gonna be required around the world as developing countries continue to increase their GDP and increase the opportunities for their people. That human development aspect of the energy discussion has been largely excluded.
Yes, it's true. We have to avoid warming the planet and cooking ourselves. At the same time, we have to keep feeding ourselves. That part has been missing from the debate. A lot of the decisions about the energy that's gonna be consumed tomorrow are gonna be made outside of Western Europe and outside of the United States, and they're gonna continue to need what we do, and we're gonna continue to serve those markets with our tie-ins to export facilities. Energy transitions take a very long time, and energy needs grow over time. Energy transitions don't happen by taking away things or removing things. They happen by adding things. We're burning just as much wood today as we ever have, for example. We cannot ban, mandate, fine, tax, or protest our way out of this.
We have to discover and invent, and that takes time. In the meantime, we will continue to deliver the energy that people need while we gradually pivot and transition for the energy uses of tomorrow, and while doing so responsibly and being good at ESG. I'll take you through all of those things. Here, I think are the key takeaways. Our assets and services will be needed for a long time to come. Energy is essential to human development, as I said. What we do today, the assets that we use today can be used, as I'll illustrate for you, for the energy forms of tomorrow. Like renewable diesel and sustainable aviation fuel. I have some specific examples around that. The other key takeaways are think about what it is specifically that we do, and I will illustrate this for you.
In our natural gas group, we're less about the commodity than we are about the transportation of it, a lot more about the transportation of it and the storage of it, so that we can provide the deliverability when it's needed. That demand for what we specifically do and the value of what we specifically do, providing that deliverability, is growing over time. Kim will illustrate this for you on some of the experience we're having in our contract renewals. As you see seasonal variation in gas demand, and as you see increasing penetration from renewable intermittent resources and the rolling off or retiring of baseload resources, the call on what we do increases in value, including in states like California, where renewable penetration is strong.
Because it is difficult, as Richard said, to get new infrastructure sited, that means that the existing infrastructure becomes more valuable over time. The grid is tightening, and as it tightens, we're able to get more value for what we do, better rates and add term length on many of our key assets. The other thing that I want everybody to take away, hope everybody takes away, is we are in really good shape. Our balance sheet is at 4x, well inside our long-term, our long-term leverage metric. That's important because that creates capacity for us to capture opportunities, further strengthen our balance sheet or repurchase shares. You have to take that into account. You can't look at our capacity as just being what's our DCF and subtract the dividends and subtract the expansion capital.
We also have worked very hard over the years to build that capability and the option value associated with the balance sheet, and it's at the highest level, the best level that it's been, since we consolidated the company into a single C corp. With that capacity and the business prospects that Kim is gonna talk about, you can see we're in really, really good shape right now. You know, the other takeaway, I was talking with somebody about this earlier, it was in here and then it was out of here. It's not something I get asked about very often, but it is culture. We have a very strong culture, and that's illustrated in how we undertake succession planning. It's illustrated in how we all get on the same page from a strategy standpoint, how we deal with upsets, how we capture opportunities.
It's embedded in our culture. We work extremely well together as a team, and we're all on the same page. That is critically important to the success of the company. Now I'm gonna go through some of the numbers that support the points that I just made. What you have here, again, with the overall theme, energy is essential and hydrocarbons have enormous advantages. It's gonna take a long time. We're gonna continue to need more of them when we have a growing population around the world and a rising standard of living. The data that's shown here is 2022 EIA data, and it's shown for 2021, 2030, 2040, and 2050. You can see these things are all moving up and to the right.
Over that period, the U.S. population is expected to grow 13%. GDP grows faster. Renewables double over the period, but natural gas and oil product demand also grows and about in sync with population growth. This is just the domestic picture, okay? This is just for the United States. We'll get into the global outlook for demand in just a moment. The other contributions from hydrocarbons are in the things that we use every day, as I mentioned, building materials, fertilizer, plastics, et cetera. Just to give you know, put some more context on this.
In just a couple of years in the current century, China used more cement than the United States did in the entire last century when we built the interstate highway system, we built every airport, and we built most of the streets and buildings that we have today. Okay? That's how much this stuff is needed to a growing economy. There's not a substitute for hydrocarbons in making cement, steel, fertilizer, and plastics. There's no economic substitute. I'll say this, once there is one, my guess is that stuff will be stored in the same terminals we have today. Okay? All right. Next. Energy transitions take time. A few examples here. Coal took 60 years to achieve a 50% global energy share. Oil took 60 years to achieve 40%. Natural gas, 60 years to achieve 20%.
Nuclear took 80 years from discovery to widespread deployment. This is the data on how long energy transitions take, and therefore how resilient our business in serving the energy needs of today, really is. Let's talk for a moment about the miracle of nuclear energy. It was the last miracle we really had in energy. It wasn't discovered by electric utilities. It was theorized. It was a breakthrough in theoretical physics at the beginning of the last century. 45 years later, we had a bomb. 10 years after that, we had our first commercial nuclear reactor. In the late 1970s, we finally had widespread deployment. These things take a long time. What nuclear took out of just power generation as a share was 15%. That's what it took away from hydrocarbons, and that's just power.
That's not transportation, that's not manufacturing, that's not anything else, which nuclear didn't touch. These things take a long time. The stuff that we do is valuable and adds to global GDP and accommodates a growing population and gives a better standard of living. On the next page, we'll look at cost. This is a key point. You can see the US cost, compare it to what's occurred in Europe. The world needs affordable and reliable energy. Most of the growth that we're gonna see in energy is gonna happen in developing economies, and they're gonna be focused on pulling people out of poverty. You can see what the European experiment in energy shows, what an accelerated transition yields.
By that I mean trying to make do with the stuff we have today as opposed to making this transition when we really have the stuff invented, discovered, commercially deployed, et cetera, that's gonna make a very meaningful difference. What we need to do as a global society and as a species is find the technologies that are both carbon-free and cheaper than what's available today. Because if it's cheaper, let's be clear, India-- if it's not cheaper, India isn't gonna buy it. It's a very tall order, and we're nowhere close to having that today. If we're gonna be serious and truthful in examining what's required here, you recognize there's a dramatic need for additional R&D and accelerated commercialization. We're not gonna protest and ban and tax our way out of this. We need discovery and invention and accelerated deployment.
Let's talk about what we have today. Natural gas. Next slide, please. It's cheap, and it's reliable. You see it's on the far left here versus on an equivalent per MMBtu basis, the other energy forms that are available. Nearly 187 million Americans rely on it, 5.5 million businesses. It's reliable. Less than 1% of natural gas customers experienced an outage over the course of a year, whereas there's an average of one outage per year per customer in electric distribution system. Just 1% of natural gas customers experienced it. In the electric side, it happens once a year to the average customer. It's safe, it's reliable, it's low cost, and it's indispensable, and the network that we have is irreplaceable.
You could make a similar argument about refined products as well. We produce this stuff, we gather it, we transport it, we refine it and process it. We transport and distribute it again. It shows up in the gas station cheaper per ounce than the water that you can buy in that same station. The infrastructure we have is extraordinarily advantaged. Now we're gonna need more of it, more natural gas. You see here, we needed increasing quantities around the world, 19 BCF a day incremental needed by 2050. That's more than 40% of what we use today. If you take into account the declines, we need something more like 25 BCF a day, which is almost 60% more than what we have today.
A lot of that's gonna have to come from the United States. This is an enormous opportunity for us in the United States. Much of the growth and demand is coming from Southeast Asia, India, and the rest of the world. It is key, fundamental, and true, but often overlooked that what we do is essential to developing economies around the world. U.S., shifting specifically to the U.S. We've got growth in natural gas production. We have declining production in other areas, and we have a lack of scale in other areas. The U.S. will be an important contributor to this, and this is obviously very important to us as a U.S. midstream company. We have nearly 100 years of reserves. We have the most competitive market.
We have the best natural gas transportation and storage infrastructure on the planet. The world's energy buyers can come to our shores and be met by dozens of producers competing for their business, investor-funded liquefaction facilities and shipping available to meet their needs. If our politics don't screw this up, we have a tremendous opportunity for the United States resources, our infrastructure, U.S. manufacturing and labor. I think this has been apparent to prior administrations that have licensed and approved additional LNG facilities, and hopefully with events in the world, we're increasingly discovering it again. Staying on this slide now. This is again, going to the U.S. role there. What's on here in the bar charts is blue. The blue is the U.S. natural gas source to meet the growing LNG demand.
On the right, you see our reserve base, almost 90 years in natural gas, almost 91 years for U.S. oil. At the bottom, you see the growth between 2021 and 2030 in U.S. exports, both of natural gas and of oil. Going back over here to the natural gas side, the two dotted lines, the two vertical dotted lines are looking at two different scenarios. One is 100 million tons per annum of new LNG capacity needed by 2035. The other is in a so-called delayed transition scenario, and it's more like 170.
Because of the difficulties of energy transitions that I was talking about before, I know which one I would bet on, but in any case, what it, what it drives is it's a significant need for U.S. natural gas demand, which will increase demand for our infrastructure. We serve 50% of that market today. We're well-positioned, as Kim will take you through, to attach additional load to the network that we have today. Long live resources at attractive prices, and that's gonna drive the growth in natural gas and oil exports, and that's gonna drive the value of the infrastructure that we have. Here's a reason for hope, right? This is the U.S. experience showing energy production and also emissions. Here's the bottom line.
Our economy grew between the period of 2007 and today, our economy grew by 45%, while emissions in the power sector declined by 36%. We can't let the perfect be the enemy of the good here. This is extraordinary progress. If we flip to the next page, we can make it happen elsewhere as well. This is showing the opportunity for a reduction in CO₂ emissions between now and 2050 of 26% to the extent we can use U.S. natural gas to displace coal. That's where that benefit is coming from, primarily. U.S. natural gas to displace coal elsewhere in the world. We have plenty of it. We've got the infrastructure that's required to get it there.
To the extent we can use it, we can accomplish a great deal for emissions reductions around the world. This is getting into the point made earlier about the importance of our assets and our deliverability specifically, and the value of deliverability separate and apart from the value of the commodity. There are two. On the left-hand side, you see during a couple of key events, how much energy storage capacity we needed in order to meet, in this case, extreme weather events. It runs between 40 BCF and 50 BCF a day of natural gas equivalent in order to meet those swings. We experienced something similar in Elliott. We had demand that hit 160 BCF.
We had total supply around 80 BCF, the rest had to be made up with storage. On the right-hand side is translating that into terawatt-hours, a power equivalent, you see 50 BCF of natural gas is about 6.1. 1.5 is the expected installed battery capacity by the time you get to 2050. The other disadvantage that battery storage has is it just simply doesn't last very long. If you have a significant weather event, you use it's gone. Typically, it's a one hour to eight-hour time period that it's gonna get used over. If the event continues, natural gas storage can continue as a solution. You don't have time. You don't have the flex to recharge the batteries.
This is why natural gas storage is gonna be required in order to meet variability in demand and do so more cheaply for a longer period, a longer duration and more reliably than you can with battery technology, even if you fast-forward to 2050. On the next page, this is taking it through to a couple of recent events, and this is again expressed in power demand and how natural gas was used to meet it. On the left-hand side, this is Winter Storm Elliott that we experienced just last month. On the right-hand side is a July heatwave. You can see when temperatures plummeted during Elliott, look at the period between 12/23 and Christmas Day, power demand increased by 25%, wind generation decreased by 37%, and natural gas increased by 63%.
Similar story during the July heatwave, wind dropped by 52% compared to the prior six days. Gas increased by 28%. Those two numbers, that 52% on wind was about 176 GW for the day. Gas was 191, gas more than offset the decline. The point of these last two slides is that not only the power sector needs natural gas, but they need what we do, providing deliverability, using storage and transportation even more as renewables are added and more base load power is retired. Further, you know, as shown on the previous page, renewables plus batteries don't even come close to getting the job done, even if you fast-forward to 2050. On these three columns, just talking about what we're doing today, this is at Kinder Morgan.
What are the opportunities that we're taking advantage of in the energy transition and what we're doing to participate in the R&D that's gonna be required. First, we're providing on the left-hand, providing our services in an environmentally responsible way. We've been reducing our methane emissions and methane intensity and reporting on our performance and our progress in our ESG reporting and our communications with the ESG investing community. In the second column over, we're positioning ourselves for and participating in the gradual energy transition in a way that is very responsible for our investors. We are participating in these markets today in RNG, in renewable diesel, renewable feedstocks, in backstopping renewable power in our gas business, and we're doing it at returns that are attractive for our investors. That's the responsible way for us to participate in it.
We're also using our CO2 expertise in carbon sequestration. We announced last week our first transaction in what we hope will be a growing opportunity for us as soon as the permitting process for sequestration sites can speed itself up. Finally, R&D. These are a number of things that we're participating in because, as I said before, massive R&D investment and really public R&D investment is going to be required to really invent, discover what we're going to need for the future. In the meantime, what we do will be needed for a very long time. A couple of specific examples of how, in that second column, how we're participating in the, in the transition.
Said at the very beginning, what we do will be needed for a long time, but it's also the case that, it's we're well-positioned to handle the commodities of the future, whether that's CO2 sequestration or new energy commodities. This is talking about the attractive potential for biofuels in the United States. We can handle these fuels, and we do today with the assets that we have, and we're making capital-efficient investments to modify and expand and accommodate our facilities in our Terminals group on the lower river region, where we are handling an increasing amount of renewable feedstocks and have a couple of tanks that are close to completion for one of our large customers there.
We're also handling it in our refined products business on the West Coast with renewable diesel hubs that we're establishing in both Northern and Southern California. This is how we can participate in the fuels. One example of how we can participate in the fuels of the future. On this slide, we're showing what we're doing to responsibly pivot to the new energy world. We're showing our ongoing activities to reduce CO2 equivalent emissions. That's here on the left-hand side. We've identified about 17 million metric tons. On the right-hand side is new projects that amount to just under 10 million tons. Again, we're doing this, it's a gradual transition. We are gradually pivoting, and we're doing in a way that's very responsible for our investors.
Have to be good at ESG if you're gonna be in the hydrocarbons business, and we are good at it. We're well ranked in it. Environmental, social and governance considerations have been central to us for a long time, whether that's corporate governance and structure or working with the communities where we have our assets. Most of our assets, all of our pipeline assets are on other people's property. We've had for a long time. Had to be good about how we interact with the communities along the way and have to do the work to keep our employees, our contractors, and members of the public and the environment safe. This is stuff we've been doing for a long time. We're reporting it and putting it in the formats that many of the ratings agencies wanna see.
These things matter. They're good metrics. They're important to our coworkers, our shareholders, our customers, our regulators. I'll make one quick point about this. As hard as we and other companies are working on this, and as hard as the various agencies are working to get this right, the fact that we've started to seek, we have sought assurance around our ESG reporting from third parties, this stuff is still developing. To elevate to the level of financial reporting is a mistake given its current state of development. That's something that we're obviously closely monitoring and taking an eye on. We're working hard on this, so are others. To think that it's at the level of where financial reporting is just. We're just not quite there yet. It's gonna take some additional time.
Finally, coming back to where we started, what we needed, to move the fuels of today and the future, we are essential to a clean, reliable, and affordable energy future. Again, we can do it for today's energy, we can do it for tomorrow's energy, and the value of what we do, specifically our deliverability, is growing in value, and our company is very, very strong. We are well-positioned. Our balance sheet is in great shape. We've got good opportunities in front of us. We're in a really strong position and a good moment right now. With that, I'll turn it over to Kim to give you more of the hard facts.
Okay. Strategy and execution. I'm gonna begin where Steve left off. We are well-positioned for 2023. If you look at adjusted EBITDA, we're gonna generate $7.7 billion in adjusted EBITDA. That's about 2% growth from last year. Our debt to EBITDA is at 4x . That's the lowest year-end net debt that we've had since the entity consolidation when we put KMP and KMI together in 2014. We have nice balance sheet capacity. We've got $3.6 billion of balance sheet capacity. Let me say a couple of things about that. You know, we are happy to preserve this flexibility. This, you know, money, this capacity is not burning a hole in our pocket.
But it is nice to have to the extent that we can do some opportunistic share repurchase or that we find more attractive projects in addition to what we already have in the backlog. Again, happy to preserve the flexibility. We'll just use this more on an opportunistic basis. Our backlog multiple, we've got $3.3 billion in our backlog at a 3.4x multiple. We'll go into that a little bit more later in the slides. Shareholder returns. We expect to return $2.6 billion through dividends to shareholders in 2023. We generate significant cash flow. We take that cash flow. We internally finance our growth projects.
We pay our dividend, then we've got balance sheet capacity, you know, opportunities that present themselves, you know, in terms of share repurchase or attractive projects. You know, start moving to the bigger picture for a second. You know, the U.S. production continues to recover from the pandemic. If you look at natural gas production on the left, you know, we are well above pre-pandemic levels. The natural gas production has been just amazing. WoodMac is projecting... You know, if you look at the WoodMac what they project for 2023, you know, versus three years ago, the actual, we are up 10 Bcf a day. We expect continued growth, which we'll go through a little bit later in the presentation. Just amazing story on natural gas.
On crude production, it continues to recover from the pandemic. During 2023, we expect that we will hit pre-pandemic levels. On the refined product side, those have recovered, but the recovery has flattened a bit. We'll talk about some of our assumptions in 2023 around those volumes. Now, drilling down on natural gas demand. I told you it's increased by 10 Bcf a day over the last few years. If you look over the last seven years, it's grown by 28 Bcf a day. That's a 36% increase in natural gas demand. If you look at the volumes on our system, the volumes on our system have increased by a similar amount. They're up about 35%, going from 30.8 BCF- 41.5 Bcf a day.
For sure, we have added capacity during this timeframe. If you look at many of our long-haul systems, you know, they are very highly utilized. What you see on peak days is that we have constraints. Just to give you a couple examples of that, on TGP, if you look at our utilization in 2015, it was at 86%. You look at it in 2022, it's at 97%. That's on average. If you look at EPNG, it was at 67% in 2015, and now it's at 86%. It is difficult in this day and age now to build incremental capacity. As a result, what we're seeing with this high utilization is, you know, favorable recontracting.
Where we can under the regulatory regime, we're able to increase rates. You know, we are able to and reduce recontracting risk. We're able to push out our terms on our contracts. For example, if you look at the average term on our Texas intrastates, we've gone from 3.5 years- 5.7 years since 2015. + 2.2 years in contract term. As a result of this, you know, what you're seeing is that we don't have the same recontracting risk going forward as we've had in the past because these systems are filling up. You know, the other thing is, as the system fills up, this leads to some expansion opportunities in the places where you can still expand.
That's primarily in the Gulf Coast, but that's also primarily where the demand growth will come. Now, on the storage side, you look at storage capacity hasn't increased. It's only increased 1% over this timeframe. The Kinder Morgan storage positions increased by about 3%. Now, we're taking out acquisitions and divestitures just to show you know, what's really happening to the actual storage capacity. You know, previously, and Steve went through some of this, you know, the demand volatility has been historically driven by weather. With the addition of renewables, you're seeing increased volatility. You saw that on the slide that Steve showed, where natural gas had to ramp so much during a winter storm because demand goes up, and a lot of times during these weather events, the renewable capacity comes off.
You know, he gave you the example during Elliott. You know, peak one-day demand during Elliott was 162 BCF. On that same day, supply, which is normally around 100 a day, dropped down to 86 BCF because of well freeze-offs. That meant that 76 BCF had to come out of storage to meet demand. As a result, you know, that means we have been able to also increase rates and increase term on our storage portfolio. Right now, in terms of a greenfield, brand new greenfield, storage facility, you know, building one of those, our rates today are still below what would be necessary to undertake something like that.
There's still a increment there before we think new storage capacity or significant new storage capacity gets built. On the products and terminals assets, you know, they don't have the same underlying market growth, but they are highly utilized assets, and they'll be needed for a long, long time to come. You know, both products and terminals have a significant amount of their revenue that has inflation escalators. If you look at the products, you know, 2/3 of our products segment EBITDA has annual inflation-linked tariffs, and that's largely as a result of the FERC tariff inflation escalator. You know, that inflation escalator in July of this year was 8.7%, or July of 2022 was 8.7%.
You know, in July of 2023, you know, right now the projections are that that could be over 13%. You know, likewise, on the terminal side, 75% of our segment EBITDA has annual price escalators. You have nice increases in revenues built in through those inflation escalators to the extent that we can hold our costs below those which we have been successful in doing in the past. On the volume side, you know, products volumes in our budget, and David will go through this, we're expecting about a 3% increase in volume. That is, you know, that's very little growth in gasoline demand.
Where we're projecting the growth is really in diesel associated with our renewable diesel projects coming online, then in jet fuel as a result of international demand coming back. You know, on the terminal segment, volumes don't have as much impact. That's because on this in this business segment, 70% of our contracts or our revenue comes from take-or-pay contracts. What that means, it's like when you rent an apartment. You rent an apartment and you don't stay there, you pay for it anyway. On our tanks, you know, you pay for it. Once you contract for those, you pay for them whether you use it or not. In the short term, we don't care about the volume that moves through those terminal facilities.
In the long term, you know, we want them to be highly utilized so that we can renew those contracts. If you look at our historical utilization or capacity leased, you know, we've run in the 90%, and in 2023 expect to run around 94%. Moving to our strategy. In the last 25 years, now almost 26 years, our strategy really hasn't changed much. We do respond to changing circumstances. The primary change has been in the in the second column here, you know, to invest in a low carbon future. We established the Energy Transition Ventures group in 2021. In a minute, I'm gonna talk about all their accomplishments. You know, in our $3.3 billion backlog, 82% of that backlog is associated with lower carbon investments.
Those are things like natural gas, you know, renewable natural gas, biofuels, and carbon capture. We still focus on owning stable fee-based assets that are core to the energy infrastructure, you know, and obtaining multi-year contracts. We're focused on maintaining financial flexibility. As I mentioned earlier, right, we project to end 2023 at about 4x debt to EBITDA versus our long-term target of about 4.5x . You know, and we have ample liquidity. We've got a $4 billion revolver. We're very disciplined in the way that we allocate our capital. We target returns that are well in excess of our cost to capital. You know, if you think of on average, you know, we target around 15%.
You know, some projects are a little bit less than that, where we have long-term take or pay contracts with good credit quality customers. You know, projects that have more variability in the revenue stream, then we may target a little bit higher than that, but in and around 15%. When we model those, we use conservative assumptions. You know, when the contracts roll off, you know, we're generally assuming that there's some degradation in rate, and we try to be conservative on the terminal values that we use in those models. The other piece of the disciplined capital allocation is on the balance sheet. You know, we have reduced debt by $11 billion since the Q1 of 2015. That has put this company in a very strong position.
The final prong in our strategy is really focusing on enhancing the shareholder value. We do that through the through the four things we've mentioned in the columns preceding this one, but also returning cash to our shareholders. We return substantial cash to our shareholders through the dividend, and we target to grow that dividend a little bit every year, and generally in line with the with the base business. To the extent that we have money above that, we opportunistically do some share repurchase, and we did $368 million of that in 2022. In 2022, we executed pretty well on the strategy. We generated $7.5 billion of adjusted EBITDA.
That was a 10% increase over 2021, which is, you know, fantastic in a stable fee-based business like we have. We were up about 5% versus our budget. You know, we ended the year at 4.1x debt to EBITDA versus our target of 4.5x . We returned $2.9 billion of money to shareholders through the dividend and the share repurchase. We brought $400 million of projects online, and then we added $2.4 billion to the backlog. I'll take you through some of these projects in a minute. You know, just seeing a lot of opportunity out there. We acquired some two RNG businesses for a little under $500 million, and then we sold an equity interest in our Elba JV.
People say, "Well, you know, why are you selling assets?" The answer is, we're economic creatures. If we can sell an asset at a high multiple and reinvest that capital at a much lower multiple, then that is a value-generating transaction for our customers. We sold Elba at about 13x . You know, if you look at the multiple on our backlog, it's less than 4. If you look where our shares trade today, it's less than 10. We can take that money and reinvest in more attractive opportunities. Where we find those opportunities, we don't find them often, but when we find them, we are happy to pursue them. You know, one of the pillars of our strategy is owning stable fee-based assets, and part of that stability comes from the contract structure.
If you look at contract structure, 61% of our adjusted EBITDA comes from take-or-pay contracts. When you think about the price-volume equation in revenues, that means price is fixed and volume is fixed. We talked about that on the terminals assets. You know, you rent the apartment, you rent the tank, you pay whether you use it or not. highly stable, 61% of our business. 26% of our business is fee-based. What that means is price is fixed, volume is generally not fixed. On the volume side, you know, the assets that make up this 26%, you know, we generally operate in a pretty tight band.
Let me tell you know, excluding the pandemic, you know, I think if you look at the extremes, you know, that's probably ±10%. When you see those extremes, those extremes would be things like, you know, tremendous increase in commodity prices or tremendous decrease in commodity prices or a very deep recession. Let me give you an example of that. And again, all this is excluding a worldwide pandemic. You know, in 2007, you know, in 2008, when you look at our products pipelines volumes compared to 2007, you know, they were down about 7%, okay? That is a pretty deep recession. You know, we probably budgeted, you know, 1% or 2%, couple of percent growth.
You know, those volumes were down a little under 10% versus our budget in an extreme event. You know, if you look at the past five years on our GMP volumes versus our budget, and you exclude 2020, the pandemic year, you know, we were within about 4% of our budget. You know, much more closer to our budget versus 10% that you might see at the extremes. On hedged, you know, 6% of our segment EBITDA is hedged. What that means, it's just like the fee-based. Price is fixed, volume is may not be fixed or generally is not. Here on the volume variability, this is primarily associated with our CO2 operations.
When you look at us versus our budget, we're largely able to call our shots. You know, we have been, you know, within 1% of budget over the last nine years on that business. Not a lot of volume volatility here either. 7% of our business is EOR, we're exposed on price and on volumes. You know, our sensitivity here, the primary sensitivity we have is to crude oil volumes, and that sensitivity, as David will take you through, is $5.8 million in EBITDA per $1 move, $1 per barrel move in the price of crude. Also contributing the stability of our cash flow is our customers' need for the products that we transport and store.
They need these to run their business. 71% of our customers are end users. For example, they're LDCs that need the gas to serve their customers. You know, they're industrials, you know, a cement plant or a plastic plant that need the gas in order to run their business. 71% need this to run their business. 76% of our customers are investment-grade credit rated or have substantial credit support, post substantial credit support. If you look at the customers that are B- or below rated, you know, that's and you consider, you know, what we could remarket capacity for and the collateral that they posted, you know, less than 1% of our net revenue is exposed to customers that are B- related, after you take those two things into account. Very strong customer profiles.
Part of delivering value to our shareholders is originated projects with returns that are significantly in excess of our cost to capital and delivering those on time and on budget. On this slide, we're looking back. Looking back over the past three years, 2020, 2021 and 2022, at the projects that we have brought online. We've spent $2.2 billion. You know, we estimated when we entered into the contracts to do these projects that we would have a first year or year two EBITDA multiple, achieve an EBITDA multiple of 5.1x. We had some cost savings on those projects, what we actually achieved was better. We achieved 4.6x. A big portion of the $2.2 billion in projects we brought online were natural gas.
You see a similar story here. You know, 5.3x was our original estimate, and then primarily due to cost savings, came on at 4.5x. These multiples, on the next page, we're gonna go to our project backlog. You're gonna see there we have a 3.4x average multiple on the backlog. These multiples are a little higher than that. Let me say, you know, we target certain returns, and those returns, as I said, around 15% unlevered after-tax returns. Those returns are well in excess of our cost of capital. That doesn't mean that we expect forever and ever to be able to do projects at 3.4x or 4.6x.
We are willing to do projects that may be at a little bit higher multiples than this. Again, as long as they meet our return criteria of 15% or better, again, sometimes a little lower, sometimes a little higher, just depending on the stability of the cash flow, as long as they meet our return criteria substantially in excess of our cost of capital. Here the multiples are a little bit higher than the backlog, and that's because there's some greenfield projects that we brought online, which tend to have a lower multiple than, you know, when we're building directly off of our existing network. PHP is in this group of projects. We had a terminals project for a very large customer that was going to leave us.
Again, you know, the returns we earned on it were well in excess of our cost of capital, but we were able to keep that customer. That was at a little bit higher multiple than the 3.4x in the backlog. Again, we're targeting returns. Those returns in the future may result in, you know, higher, maybe lower multiples, but again, always significantly below our cost of capital. Looking forward, on the $3.3 billion capital backlog, you know, we ended 2021 with roughly $1.3 billion in backlog. During 2022, we originated new projects of $2.4 billion. You know, really good year in terms of finding new opportunities. We put about $400 million of projects in service.
We added roughly $2 billion to the backlog on a net basis to go from $1.3 billion-$3.3 billion. As I said a minute ago, those projects, the EBITDA multiple on the projects, excluding CO2, about 3.4x, and 82% of those projects are lower carbon projects. As we look forward, you know, historically, you know, 3+ years ago, we used to say we expect to spend, you know, $2 billion-$3 billion annually, and we've said this on a number of calls. Right now, our estimated pace is more like $1 billion-$2 billion. We're spending a little bit over that in 2023, as David will show you. Now, many have asked, you know, what are the projects that make up this backlog?
This goes through some of the major projects that make up the backlog. The biggest project in our backlog is the TGP and SNG pipeline project to serve Venture Global. It's a two BCF of capacity moving on a combination of SNG and TGP. We've got 20-year contracts. The project will come online in 2024 and 2025. You know, the second biggest project is a $283 million project. This is a debottlenecking project within our Texas intrastates that will come in service late this year. You know, KinderHawk, the Haynesville, as I'll show you in a minute, has tremendous production growth. You know, given all the demand for LNG exports, it was just born in the right place.
We've got a lot of opportunity there on our gathering assets. The TGP's 300 expansion, that's a pipeline expansion to bring incremental gas into New York. It's a compression expansion. Compression expansions tend to be highly economic. We've got 20-year contracts there that comes in November 1 is our projected date on that. Those are some of the natural gas projects. On products, it's really the renewable diesel projects. $73 million of renewable diesel projects we'll go through in a minute. In terminals, we have the feedstock, the renewable diesel feedstock hubs for REG slash Chevron and for Neste. We've got a conversion project which lowers greenhouse gas emissions in Pasadena by 38%, for $64 million.
We've got the ETV projects of about $300 million, you know, converting some of the gas coming off the landfills to be pipeline quality. That gets you to about 84% of the backlog. These are the biggest projects in the backlog. Okay. You know, before we go through the individual segments and break down the relative contributions for you. You know, natural gas pipelines, about 62% of our segment EBITDA. You know, Richard said that the other three are kind of roughly equivalent, and you can see that here. 15% on products, 12% on terminals, and 11% on CO2. If you broke this down based on, you know, the commodity type, you know, you say 62 is gas.
You have about 20% of our business that is refined products when you combine what's in the product segment and the terminal segment. You've got 10% that is CO2 related, you've got 8% that is either crude, bulk terminals, or Energy Transition Ventures, what I call other. That gives you a sense for how the business mix breaks down. We'll start with natural gas, you know, where we own the largest gas transmission network with about 70,000 miles of pipe. We transport about 40% of the natural gas that moves in this country, our storage position is about 15% of the U.S. market. We've got about 700 BCF of storage. Now looking at what's expected to happen on the supply basins in natural gas.
You know, WoodMac is showing about 20 BCF a day growth in supply between 2022 and 2030. Where is that growth coming from? It's really coming from three primary basins. You know, the biggest piece is the Permian, expected to grow by 10 BCF per day. You know, once we get the PHP expansion online, which will happen later this year, you know, we've got over 8 BCF a day of export capacity out of the Permian. You know, almost five of that, you know, really moves to the Gulf Coast, and then the rest moves to the West and Mid-continent through EPNG and NGPL. You know, the second largest growth in terms of just BCF per day is coming from the Haynesville.
There, as I showed you in our project backlog, we have a lot of opportunities to deploy capital associated with this 8 BCF a day of growth. The Northeast is about 5 BCF a day, and our TGP pipeline, you know, runs through the Marcellus Utica. It's kind of bifurcated. It takes gas into the Northeast to meet demand there, and then into the Gulf Coast primarily to meet LNG demand in the Gulf Coast. You know, really nice picture on the supply side, and we are able to access the basins that have the most significant growth. On the storage side, as we've said, we've got the largest storage position.
You know, as Steve talked about and I've talked about, you know, storage is really the key to supporting the variability in natural gas demand, that has increased from just being weather driven to being also driven, you know, by a renewable load, which, you know, decreases a lot of times during, well, when the sun quits shining or the wind quits blowing, and that happens many times during storms. Then the variability with LNG demand. You know, right now, Freeport back online, there's about 14 BCF a day of LNG export demand once you get that facility back online. If the market fundamentals are, you know, change, then people may not be pulling that gas away. Then it's gotta stay, and you've gotta find a place for a lot of gas.
You know, storage is the key to balancing that volatility. You know, we have some ability to balance through the pipeline services that we offer, not just the storage facilities. The non-ratable services that we offer, whether that's on the, on the pipeline side or that's on the storage side, you know, they get priced at a premium, right? Because it's harder to manage that demand. You know, our no-notice service, our pressure guarantee service, all those things get priced at a higher margin than what our base load demand gets priced. We've talked about supply. On the demand side, Woodmac projects demand growth that largely is in line with the supply growth.
You know, 95% of the demand growth is expected to occur in Texas and Louisiana. If you look at the map on the right, I mean, our system is very well-positioned to serve that. LNG demand between 2022 and 2030 is expected to more than double. Demand to Mexico is expected to grow by 3 Bcf a day. The industrial demand is expected to grow by 3 Bcf a day. Power demand is actually expected to decline by about 3 Bcf a day. On the next slide, I'll talk about the LNG and our position and ability to serve that.
On the exports to Mexico and the industrial demand, you know, that 6 Bcf a day of growth, you know, if we really see, more de-globalization, I would say there's probably upside in those numbers. If you really see a lot of industry coming to the U.S. and moving out of China and other places across the world. Now on the power side, you know, they may need less base service from us, but as you know, Steve has showed you know, they're gonna need more non-ratable services, which are premium services. You know, there's ability to offset that decline in demand. All right, now looking at LNG. Today we're contracted to move about 7 Bcf a day of LNG, and we're around roughly 50% of the market.
We've got another 3 Bcf a day that is, we have signed contracts for, and that the facilities will come online, we're projecting in 2025. At that point in time, we'll have 10 Bcf a day of contracted LNG capacity. The market, and this is a Woodmac projection, is expected to grow to 26 Bcf a day. Given our asset position in and around the Gulf Coast, there should be opportunities for us to serve this, and many of them we can do in very capital-efficient manners. You know, we are going to maintain our financial discipline. If someone else is willing to build a pipeline on spec or willing to do it at very low cost of capital, you know, we're not gonna compete with that.
Given the pipeline network that we have, you know, we should be able to provide cheaper alternatives where we can build off our existing system than new build capacity in many cases. We're in a very good position on the LNG for the LNG growth. On the product segment, we're the largest independent transporter of refined products. You know, pipes are the cheapest and safest way to move refined products. We've got about 100 mi of pipe, primarily, as you can see on the map, in the West and in the Southeast. We move about 2.2 million barrels per day. That breaks down roughly 3/4 of that volume is refined products, with the biggest piece of the refined products being gasoline. Gasoline's about 60% of the refined product volume.
We've got about 25% that are crude volumes and kinda equally split between the Bakken and the Eagle Ford. Tank capacity in our products group, we've got 56 million barrels of tankage capacity. Refined products has been a very steady contributor for our business. If you look at the volumes, since 2015, you know, the volumes are relatively flat, you know, up 0.1%. You know, now that's better than the market overall. If you look at the market, it's slightly down. We're a little bit better than the market. Now, the other piece of the, you know, on the price side of the equation, you know, we have the inflation adjusters we talked about.
As a result, even though we haven't had a lot of volume growth, you know, our adjusted segment EBITDA has grown by 3.2%. The, you know, expansion projects have also contributed some to that. But we're doing better than what you see the volume growth. What happens on the inflation escalator is these are, you know, high fixed cost, low variable cost business. If you can get two or three or, you know, right now a lot greater growth on the top line, and you can manage your cost appropriately, then, you know, you get that operating leverage, and you can have a little bit better growth on the bottom line. You know, on the refined product side, we're also seeing opportunities on the renewable diesel, which I'll take you through on the next slide.
We found opportunities on the blending side, blending naphtha or blending butane. On the renewable diesel projects, we've got about $73 million, all on the West Coast. The demand for renewable diesel is really driven by the federal and state subsidies, which encourage the use of biofuels. The subsidies are most significant in California. In California right now, these subsidies are about $4 per gallon. Most of these projects that we have, you know, we've got some in Southern California, some in Northern California, and you know, they're expected to come online in the Q1 of 2023.
This is a lot of what's driving the diesel growth, diesel volume growth in our products pipelines in 2023. Now moving to the terminal segment, you know, we're the largest independent terminal network. If you take the terminals that are in products and you combine them with the liquids terminals that are in the terminal segment, we've got 134 million barrels of liquids capacity. Very significant position. Within the terminal segment, if you just look at the liquids piece, so the liquids, and we include the Jones Act in that's about 75% of the segment, and then 25% is really the bulk business, you know, where we are storing and moving for customers.
You know, petcoke, steel, and coal are the three largest products. As you can see, our terminals are spread, you know, across the coast and through the inland waterways, across the United States. Now, not all liquids terminals are created equal. Some are just pots and pans and buckets. John and his team have worked really hard to create hubs, which have tremendous connectivity and liquidity for our customers. Houston is the prime example of this. It is our largest liquids terminal. You know, within the terminal segment, it constitutes a little over 50% of the liquids capacity. We've got 43 million barrels of capacity in the Houston Ship Channel.
You've got 31 inbound pipes. We're connected to 10 refiners, and that's 2.5 million barrels of output a day, refined product output a day that comes out of those refiners. We're connected to eight chemical facilities. We're connected to Mont Belvieu. You have a lot of products coming in, primarily refined products, but also chemicals, and then, you know, some products that are used that our customers use for blending. We've got 18 outbound pipelines. You know, the two biggest, Colonial, which move product into the Southeast and into the Northeast. Explorer, which goes in the Midwest to Chicago. We've got cross-channel lines, which connect, you know, our terminals. We can freely move product between Pasadena and Galena Park.
You know, our customers can go outbound on the pipes. They can go outbound on the ships or barges. We've got 11 ship docks. We've got 39 barge spots. They can also go over the truck rack into the retail market, you know, in and around Houston. We've got 35 truck bays. We also have unit train facilities, which, you know, bring in primarily ethanol. We also have the ability to take refined products outbound. A lot of people can build tanks, but replicating this this group of assets and the connectivity that we have in this is, you know, is really near impossible. Jones Act market. Really good underlying fundamentals right now on our Jones Act tankers. We've got 16 tankers. They're about eight point eight years old.
The industry dynamics have tightened significantly. That's for a couple of reasons. One, the Russia-Ukraine crisis. Two, moving RD from the Gulf Coast to the West Coast, where it's most profitable to sell. Three, there's some statutory limitations, new statutory limitations on issuing waivers. You know, rates have increased significantly. If you look at rates, they've improved from $58,000 a day at the end of 2021, and spot rates right now are about $75,000 a day. Now, that's a spot rate. You know, long-term contracts may be a little bit less than that, but that gives you a sense for the increase in the market.
If you look at, you know, how that market compares to, you know, what it would take to build new ships and bring new supply, tanker supply onto the market, you know, those rates, it would have to be $100,000 a day, $100,000 a day. You know, you have a fair amount of room between where we are and where new supply would be brought on. We've not only increased the rates, but we've also increased the term. The term has increased from of our contracts has increased from 1.3 years in 2022, now to 3.3 years today.
That doesn't include likely options, option where our customers have options to extend those contracts and the rates are such versus the market that they would probably do that. If you included likely options, the term would be a little bit longer. When you look at our charter profile, you know, we've got 93% of 2023 is under firm charter. 93% of our capacity is under firm charter. You compare that where we were last year at this time, we were at 19%. Just a dramatic change in the market. If you look at the likely options that will be exercised in 2023, we're at 100%. You know, if you look at 2024, we were at 25% last year at this time.
We're at 79% and likely over 90%, if you include the likely options. Just really nice change in the underlying fundamentals on the Jones Act, and that's driving some nice EBITDA growth in our terminal segment. Another place where we're seeing growth on the terminal segment is on RD feedstock, renewable diesel feedstock projects. We've got two feedstock projects, both in the lower Mississippi, one for Neste and one for REG, now Chevron. It's, you know, $134 million of total investment. It's about 900,000 barrels of storage. You know, the Neste project is almost complete. You know, it'll be complete during this quarter. The REG project will complete at the end of 2024. There, we're really just starting that project.
You know, this at on the Neste project in particular, one thing that we're seeing is this is new business coming into this terminal. As a result of that, you know, occupancy in that terminal is going from what has historically been 70%-80%, you know, and it's gonna go close to 100%. The other thing as a result of that we're seeing is the ability to increase rates. You can see a similar story here, whereas, you know, as demand increases, as you bring in new business, the market expands, our assets are filling up, and that allows us to increase rates and/or term. All right, turning to CO2. In the CO2 segment, we've got five oil fields in the Permian Basin in West Texas.
Really it's 2 fields, Yates and SACROC, that are the most significant fields, and they account for, you know, over 90% of our net oil production. We have interest in three CO2 fields, two of them in southwest Colorado, we have pipelines that connect those CO2 source fields to the oil fields. What we're doing is we're bringing CO2 down, injecting it into the oil fields in order to produce oil. CO2 is used in tertiary oil recovery. You know, right now, we're moving a little over 900 million cubic feet a day of CO2 down the Cortez Pipeline primarily. It's got capacity of, we've got capacity of 1.5 BCF, room to grow if needed.
You know, we take that CO2 that we're moving, we sell a portion of that to third parties, and then a portion we use to flood our fields, and we produce about 30,000 barrels a day of oil net to Kinder Morgan. Now, this business generates very consistent cash flow for us. If you look on the at the operating cost versus the cash operating cost versus the prices we achieve, if you look at the two most recent years, cash costs are about $25 a barrel. You know, we're getting $64-$67 a barrel. So, you know, horses and hand grenades, $40 a barrel of margin. That margin provides a return on our capital.
If you look at the chart on the right-hand side of the page, you know, we have generated free cash flow after expansion CapEx of between $350 million and $560 million. You know, these are the investments that we are undertaking today in these businesses at SACROC and Yates. You know, those fields are very developed in terms of the infrastructure that you need. Generally, the projects are about build, you know, drilling incremental wells, and as a result, you know, highly efficient capital projects and nice returns. Almost, you know, all the investment, as I said, is at SACROC and Yates. If you look at the 20 projects that we have approved right now that the CO2 group is pursuing, 17 of those projects have an IRR greater than 30%.
Okay? Three have returns that are in the high teens and into the mid-20s. You can see, you know, what I mean when I say these are very nice returns on these projects. All right, turning to Energy Transition Ventures. As I said, we set up this group in 2021 to look at opportunities really outside of our existing asset base. But, you know, these opportunities have to fit our strategy and our return criteria. The first thing the team did was they went in and started sifting through all the opportunities to find opportunities that they thought, you know, matched our strategy, and they put them into three buckets. You know, the most actionable bucket was really the first one, which is, you know, renewable natural gas, renewable power.
The second opportunity, which is the medium-term bucket, is what I would call it, is really the carbon, the CCUS or CCU-CCS, carbon capture and sequestration. The long-term bucket is hydrogen. On the hydrogen, you know, it's really, at this point, it's really more about R&D. You know, can our storage facilities hold hydrogen? You know, can we transport the hydrogen in our pipes from without causing any integrity, any integrity issues? To date, you know, the ETV that they've executed on three acquisitions, all in RNG, about $800 million of capital spent to buy those, and one CC-CCS project that we'll go over at Red Cedar that Rich mentioned in his presentation.
Looking first at the RNG market opportunities, you can see, you know, this market's expected to grow dramatically. Now, it never gets huge, but it nice growth, and it gets to a decent size. This is really about capturing natural gas coming off landfills, coming off of dairy farms, and moving those, cleaning up that gas, moving it in pipelines. Then there's two different markets today that you can sell that gas into. One is the transportation market, and when you sell it into the transportation market, you know, the renewable natural gas vehicles generate about 75% less GHG emissions than diesel vehicles because it's primarily these molecules are primarily going in to commercial vehicles. Now the, you know, they typically pay, you know, a Henry Hub or a NYMEX price for this gas.
When you sell this gas, you also get a RIN, which, the value of the RINs today is like $26, over $26 an MMBtu. On a combined basis, you're getting, you know, $30 roughly of value, when you put product into the transportation market. The other market that you can take these volumes is the voluntary market, and that's where people are interested in decarbonizing. You know, like a utility, wants to decarbonize and has some decarbonization goals. When you take it into that market, you know, it's a slimmer margin, so a lower price. There you get a fixed price, so you don't have the variability that you have with RINs, and you can get long-term contracts. So more stable business.
You have more stable business, but less upside, a little bit more on the transportation, you've got more volatility, but a whole lot, you know, more upside. You know, we target to have a portfolio that is mixed between the transportation market and the voluntary market. A new market that has recently come out, the EPA just issued their Renewable Volume Obligations for the next three years, and in that, they included eRINs. This is when you are using RNG to basically into the power market in order to use to charge the electric cars, okay? You get an eRINs. That is a market that we are, that we're currently exploring. You know, the regs aren't finalized yet.
You know, we expect that'll be finalized in June. It's something that we're exploring. When you look at on the next slide, if you look at our portfolio of acquisitions, we've done three total. In those three acquisition, we've got six potential conversions. four of those conversions are under construction today. two are not yet under construction. Now, if we do all RNG pipeline quality gas, you know, we will get up to seven BCF per year of gas off these facilities. It'll cost an incremental $300 million to convert all those. We'll have a total investment of about $1.1 billion, and we expect to bring those projects on at less than a 6x multiple.
Having said that, on the two projects that are not currently under construction, as I said, you know, we're looking at the eRINs market. There we will evaluate the two sites that are not under construction for eRINs. On the eRIN side, you know, there, if we pursued that, it would be less capital on those sites, but we still get incremental cash flow associated with the RINs that you would get. It's a nice way to reduce emissions. You can see that the 7.4 Bcf a day of RNG reduces emissions by 4.2 metric tons of CO2 per year. Turning to CCUS. You know, in this, there's multiple steps in the chain in order to, you know, capture and sequester CO2. You have your emission sources.
You've got to go capture the CO2 off those emission sources. You've got to transport it to a well where you can inject it and sequester it. You know, I think we are able to play in all three. Well, typically, we're gonna be on the capture, transport, and sequestration side. You know, more of our expertise is on the transport and sequestration side, building the pipe. Because of our CO2 business, we know how to inject that gas. We know how to, you know, look at the geology to make sure that we can contain that gas in the reservoir. You know, CCUS is economic because of the tax credits that you can get, the 45Q tax credits, which increased last year.
You know, prior to the increase, you know, it was really, you know, there were very few types of facilities, you know, natural gas processing facilities and ethanol facilities were, you know, really the only ones that you could economically do carbon capture. Now, more facilities have become economic, and so you have some natural gas facilities where it might be economic, you have some coal facilities, you have some ammonia facilities where these projects can be economic. Really, you know, the biggest gating item today, on these projects is about, you know, is about the sequestration. You need, in order to sequester, for the most part, you need a Class VI well permit from the EPA. And there have been a lot of permits filed with the EPA, but there haven't been any permits issued recently.
Texas and Louisiana have both filed for primacy, meaning they would take over this permit process from the EPA. Louisiana is much farther along. Texas just filed theirs. I think if some of the states get primacy, that could help speed up. On our next slide, the specific project that we have on Red Cedar, you know, we are. Richard said it's relatively small. It's less than $50 million of CapEx. We're involved in that, in all three pieces of it, the capture, the transport, and the sequestration. We have a joint venture with Red Cedar, where we emit the CO2 primarily from a trading facility.
Red Cedar is going to build the capture technology, they're gonna build a small pipeline down to Cortez Pipeline, which is our pipeline, which goes from southwest Colorado to the Permian Basin. Energy Transition and CO2 group will take it, the CO2, down into the Permian Basin, where we will inject the oil into an existing wellbore and think that we may be able to use a different type of permit to do that. We wouldn't need the Class VI permit, could get this project done more quickly, we think by the Q2 of 2024. In terms of volume, you know, we're talking 10-20 a day.
You know, where this market is today, I think is, you know, there are opportunities for smaller projects. Really to do the larger projects, we really need to see, you know, Class VI permits issued from the EPA or from the states if they get primacy. As Richard started off, we think this is a compelling investment opportunity. You know, we're the largest energy infrastructure company in the S&P 500. We have very stable cash flows. We've got a strong balance sheet that has a lot of flexibility. We've got a nice backlog of projects with attractive returns. We've got a 6% dividend yield, and which is, as Richard said, top 10 dividend yield in the S&P 500.
You know, we've got the flexibility to do some opportunistic share repurchase, and we've got a highly aligned management team that has 13% share ownership. With that, I think we're gonna take a break. Oh, we're gonna go to David. Okay.
Just one more before the break, so hang in there. I'll begin with our capital allocation priorities. For those of you who followed us, who know us, this isn't gonna be a surprise. These don't change for us. It all begins with a strong balance sheet. We think it's important to have leverage as part of our overall funding mix because it reduces the more relatively costly form of equity funding. We know that we have to have that leverage in an amount that is appropriate for us, given our credit profile and overall business mix. As for allocating capital to our growth capital projects, we target a 15% unlevered after-tax rate of return.
It does that rate of return does vary somewhat with regard to the specific project risk profile. The process that we follow internally is very consistent, is very established and well-known across our business, across our business units. I skipped over our maintain our dividend. We, we have a bias towards paying out a significant amount of cash flow to our shareholders. We, we think that our business mix enables us to do that in a modestly growing manner, but in a, in a very significant overall cash flow size. Finally, should we have excess cash in addition to funding our leftover after funding our dividend and our growth capital program, we look at three different ways of returning additional or creating additional value for our shareholders.
Retaining some of that cash flow on our balance sheet, using it for unbudgeted capital projects and acquisitions, and potentially using it for share repurchases on an opportunistic basis. Moving on to the next slide. What does that look like for 2023? In 2023, we expect to generate $5.7 billion of cash flow from operations. We expect to spend $2.8 billion of that on capital. That $2.8 billion includes our sustaining capital, 'cause this is a GAAP metric. We expect to spend $2.5 billion in dividends for the year, and we expect to have $2.6 billion of balance sheet capacity.
As Kim mentioned, this is capacity that's created when you take our long-term leverage target of around 4.5x compared to where we expect to end the year at 4.0x . Apply that to our EBITDA projection, and you get to about $3.6 billion. A lot of capacity. For each 0.1 turn of leverage capacity that we could utilize, that represents about $770 million or 2% of our market cap. A lot of flexibility there. When you combine that with our free cash flow that we expect to generate in the year, that brings you to about $4 billion of total available capacity for the year.
you know, one note here is we wanna make sure that it's very clear we're gonna take a very disciplined approach to utilizing this capacity. We recognize that reducing leverage on a balance sheet is a difficult task. We've been doing it for a while, and we recognize how hard that is, so we don't wanna utilize this capacity lightly. We'll take our usual disciplined approach as we look at opportunities to utilize it and how those would accrete to our shareholders' value. On the next slide, before we get into the 2023 budget, wanna spend a couple of slides looking at how that capital allocation strategy has resulted in incremental value for the shareholders since 2016.
As you can see, from 2016 through our 2023 budget, our Adjusted EBITDA has grown about 18% when you exclude the contributions from the assets that we've divested in those years. Meanwhile, we've reduced our net debt by almost 20%. On the next slide, we'll show the remaining part of our capital allocation efforts. Our discretionary capital has been robust over the years. We have reduced the overall amount of annual spend in our growth capital program. As Kim mentioned, we're now more in that $1 billion-$2 billion range. Importantly, most of our projects, generally speaking, are on the smaller size, which are more capital efficient and come with higher returns. A real quality over quantity type approach.
On the right-hand side of the page, you can see our dividends page and our shares repurchased. After a few years of more sizable increases in our dividend, we've fallen into a pattern here of more modest but steady dividend increases, which we think are appropriate and are sustainable, while also taking advantage of opportunities to return value to our shareholders in the form of stock repurchases over that time. Past performance is not always a predictor of future outcomes, but track records matter, and we think this illustrates that we're doing what we said we would do, and we're following through on our capital allocation strategies. Moving on to the 2023 published budget. Oh, I'm sorry, one last page on this.
This is really kind of illustrating the same thing, just on a GAAP basis. I guess a couple of high levels here. Our free cash flows from 2016 through our 2023 budget has increased 50%. Our net debt, as I mentioned, is down about 20% over that same timeframe. Our annual dividends have more than doubled and are now growing at a steady, sustainable pace. We've conducted about $950 million of share repurchases along the way. Now moving on to the 2023 budget. This is consistent with the guidance that we provided back in December, just with a whole lot more detail.
As usual, we're gonna post this to, or we have posted this to our website, and we'll compare back to it quarterly so you all and we can track our performance versus our expectations. We budget to generate $8.2 billion of adjusted segment EBITDA. That's up 4% from last year, last year was a very strong growing year. Good, healthy underlying business growth. Our adjusted EBITDA is expected to be $7.7 billion, up 2%. We'll talk about why that's a little bit lower. That's partially due to a higher non-cash pension expense that we expect in the year.
Our DCF of $4.8 billion, a little bit lower than last year, and that's mostly driven by higher interest expenses that we expect in 2023. We don't have any buybacks assumed in the budget, we do that because our usual approach to share repurchases is an opportunistic approach, one that we require attractive repurchase prices before we actually conduct share repurchases. We don't do it on a programmatic basis, that's why we don't have any of those assumed in the budget. On slide 70 is our EBITDA bridge, this is just to show you some of the larger moving pieces year-over-year. First, we've included the headwinds that we expect on a number of our natural gas pipelines, where we expect to have lower rates after recontracting on those assets.
This is something we've been talking about for the 2023 headwind for a couple of years, the magnitude of this impact is consistent with the prior disclosures. That's helpful. Also importantly, this is the last year that we expect meaningful recontracting risk on our assets for the foreseeable future. The bar to the right quantifies the amount of favorable recontracting that we expect in the year, along with some rate escalations that we expect. 2/3 of that bar is really favorable renewal. If you combine that or if you just compare the favorable renewals against the unfavorable renewals, it's about a wash. As I said, the unfavorable renewals, we don't expect to reoccur going forward in any meaningful way.
Nice to see the underlying base business growth and the value of our assets really shining through. The two-thirds of the favorable recontracting comes from our natural gas segment, MEP or Midcontinent Express Pipeline, favorable renewals on that asset. Our Texas Intrastate favorable renewals and our Jones Act tanker business, as Kim mentioned, is expected to have a healthy 2023. Next, we show some unfavorable impact from our G&A and non-cash pension expense. Some of this is higher labor costs, but the majority of this, the vast majority of this is a non-cash pension expense. This has to do with poor performance in our pension assets last year.
We're at a lower starting point this year, meaning the increase in asset performance in 2023 is going to be lower than or is expected to be lower than 2022. There's some complexity to pension accounting that we won't get into. We think that this is illustrative of some volatility that we've seen in the pension accounting and pension expense category that we've seen from time to time. We think a more consistent measure is the cash contributions that we make into our pension plan annually as opposed to the expense piece that's a GAAP function.
That's why we replace the non-cash pension expense with our cash contribution in our distributable cash flow metric, which ultimately ours, the cash contribution is a little bit more stable over time. But we've ultimately ended up in a similar spot as the GAAP measure. The next category are divestitures, and that's largely an impact of our partial interest sale in the Elba liquefaction facility. We have our significant growth from growth projects and some incremental volume expectations through our existing gathering and processing assets. Next slide is our interest expense slide. As we released in December, we expect some headwinds from interest expenses in 2023.
We have $7.5 billion of floating rate debt, which means for every 100 basis point change in short-term rates, we have a $75 million exposure. We also had a more than $5 billion of our short-term exposure in 2022 that expired at the end of the year. We received about a $70 million benefit from those 2022 locks, which won't reoccur.
If you look at where short-term rates are expected to come out for 2023, which is about a little bit more than 300 basis points higher than 2022, apply that to our sensitivity and add the $70 million of the lock benefit that we received in 2022, that gets you about $300 million of this $331 million. In an attempt to mitigate some of this impact in the year, we have locked in SOFR rates for about $1.25 billion of our floating rate exposure in 2023. We did that at levels that were slightly favorable to our budget, so it won't have a large move.
It also helps us mitigate some of the potential future downside risk should rates move against us. We'll continue to take a look at opportunities to mitigate the risk and potentially improve on the budget. Finally, while this interest rate headwind in 2023 is very disappointing, it hasn't changed our view on the appropriate strategy for floating rate debt in our portfolio going forward. We think some portion, some percentage of floating rate debt in our overall funding mix is appropriate, and it's created a lot of value for us over the years. We've generated $1.2 billion of lower interest expense over the last 10 years as a result of having this floating rate strategy.
Importantly, the underlying fundamentals that have driven that improved performance as a result of having floating rate debt hasn't changed. We don't think that the swap forward curves that typically overestimate the short-term movement in rates hasn't changed. We'll continue on with this strategy. On the next slide, on the top of the page, you can once again see that the primary differences between net income and our distributable cash flow are really two items. Distributable cash flow includes cash taxes and it excludes book taxes. It includes sustaining CapEx and it excludes book depreciation.
We view distributable cash flow really as a cash proxy for earnings and is therefore, a better representation of the cash-generating capabilities of our asset and our business. Moving to the bottom of the table, you can see DCF per share is budgeted to be $2.13. As some of us were mentioning or were discussing before this, if we were to remove the interest expense impact from the year, the DCF per share would be $2.28, up 4% from 2022, which is consistent with the segment EBITDA growth year-over-year. Our dividend is expected to be $1.13 per share, which is up 2% from 2022. It's greater than our DCF per share growth, but it's a little bit lower than our segment EBITDA growth.
We think that we're threading the needle pretty well there, growing it at a little bit less than our underlying business growth, but a little bit faster than our bottom-line cash flow growth. We've maintained, and we are still maintaining a healthy coverage level. On adjusted EBITDA, the next slide. This slide provides a lot more detail into some of the key drivers in our segment year-over-year performance. I won't go through that detail, but would note that it's very nice to see that in each one of our business segments, we expect growth, which is very nice.
The other piece is, if you were to exclude growth capital contributions from the 2023 performance, we would still have about a little bit north of a 1% growth rate year-over-year, just based on the underlying business growth, not accounting for the capital-related expansion contributions. A couple of items here to highlight, just to point them out. The G&A and corporate charges, that is up quite a bit. Again, that's the non-cash pension expense item that I mentioned before. The 25% year-over-year growth would actually only be about 6% if you were to remove that one item, which again, we don't think is representative of the long-term cost for us.
On sustaining capital, it's also a bit higher by $101 million, and that's due mostly to increased costs related to our natural gas segment. The primary increase is from an increased number of Class location changes that are going to be required in 2023, but there are also higher costs for turbine exchanges, pipeline integrity costs, and some additional environmental regulation. Right below sustaining capital is other items, and this is where you can see we add back the non-cash pension expense item here and replace it with our cash contribution, which year-over-year is consistent. DCF, as we mentioned before, down 3%, but more than all of that is explained by the higher interest expenses year-over-year. Moving on to CapEx. The top part of the page here is more detail on our sustaining capital budget.
Moving into the discretionary capital section, you can see $2.1 billion of total discretionary capital expected for 2023. About $1.4 billion of that is related to our natural gas segment. Of that, if you look at the key projects on the right, there are five projects there that represent collectively about $1 billion of the $1.4 billion. The rest of the $400 million or $385 million or so of natural gas, along with most of the other projects across our other business segments, are smaller, more capital efficient type projects. As Kim noted, across our full backlog, we expect an EBITDA multiple of 3.4x, and this year's spend is illustrative of some of the higher return projects that we expect.
All right, moving on to the next slide. This includes our cash flow from operations, $5.7 billion. This is all on a GAAP basis, which I know is important to many of you. We walk from net income down to cash flow from operations. There's our GAAP CapEx number of $2.8 billion to get to free cash flow of $2.9 billion. After we pay our $2.5 billion of dividends, we're left with $336 million of free cash flow after dividends. That, along with the balance sheet capacity that we covered earlier, is what provides us with tremendous flexibility during the year. Speaking of, our sources and uses on the next page.
This is just a high-level summary of our overall sources and uses to let you see the biggest moving pieces there. Our cash flow from operations, $5.7 billion. We started the year with $745 million of cash on hand. We account for the JV distributions that are picked up in our cash flow from investing section. That leaves us with a need to borrow of about $2.5 billion. We've already covered the main uses here, so I just make the note again, just like I said on the earnings call.
We do plan to access the capital markets to address our funding needs during the year, but we do have a $4 billion credit facility capacity, which gives us the luxury of remaining patient to ultimately access and address some of these borrowing needs. Moving on to slide 77. We expect to end the year at 4.0x , nicely below our long-term leverage target of around 4.5x. The only other comment I'd make on this slide is you can see on the right-hand side we're nicely, we drop off nicely after the wood that we have to chop this year. We're below $2 billion in total maturities every year for many years. That's good to see. Moving on to our quarterly profile.
As we mention every year, our quarterly shaping is not even across the year. It's primarily due to three things. In our natural gas segment, we have some pipelines that have greater performance, greater contributions in the Q1 and the Q4 because during the wintertime, we generally see higher rates and higher utilization on a number of those assets. That provides greater contributions in the Q1 and the Q4. Then in distributable cash flow, we have two additional factors that play in. One, estimated cash tax payments. We have zero in the Q1, two in the Q2, one in the Q3 and one in the Q4. We also tend to have less sustaining capital in the Q1 and then more consistent sustaining capital in theQ2 through the Q4.
So we've provided more detail on the quarterly shaping this year than we typically have, so hopefully that's useful for you all to calibrate your models as we go through the year. All right. Slide 79 on our minimum book tax. First, under the traditional federal income cash tax base of part of this, we are not expecting to be a federal income cash taxpayer in 2023. Just like last year, we don't expect to be a material federal income cash taxpayer until after 2027. On to the incremental potential federal taxes. The minimum book tax, which was just passed last year. We don't expect the minimum book tax to be applicable to Kinder Morgan in 2023, 2024 or 2025.
That's just a function of us looking out and it's a complex calculation, but it's our, it's our view of the applicability to the billion-dollar threshold looking at our taxable income and our, and our overall tax depreciation mix. Now as I said before, it is a complex calculation. We'll continue to monitor it, and we'll update you as necessary. But that's our current view right now. Slide 80 is our budget sensitivities slide. This page is really for your reference. I wasn't planning on spending any time on it. Slide 81 are our highlights. You know, really just to wrap up here and let you all get to your break. We beat our budget in 2022 by 5%, both on an EBITDA and a DCF basis.
We increased our dividend by 3%. We reduced our net debt by $300 million. We ended the year, with the lowest year-end net debt balance since our 2014 consolidation transaction. We repurchased almost $370 million of shares at an average yield of 6.6%. A pretty decent return, even excluding the terminal value from the elimination of those shares. For 2023, we expect a 2% dividend increase, a further reduction in our net debt, an improvement in our leverage ratio to 4x , and we have plenty of excess capacity, which gives us lots of flexibility should we see opportunities and cushion should we see any risks. Outstanding performance in 2023. very well positioned, excuse me, outstanding performance in 2022.
Very well positioned going into 2023. We have some firepower. With that, now it's time for the break. So-
We'll take a 10-minute break. Start right back up at 11:10. We'll bring our business unit presidents up here, we'll start the Q&A session. Thank you.
We'll start the Q&A session. Okay, everybody, 30 seconds. Okay. Thank you, everybody. What we're gonna do here for the next 30 minutes or so is, give you all an opportunity to ask questions directly of our business unit presidents. I know I probably interrupted you from doing exactly that while you were out there, at the break. In any case, this is where the work gets done. This is where, you know, our commercial strategy and our operational strategy and everything is getting executed. I think it's important for you as investors to hear what these folks have to say. That's what we're gonna do. While you're thinking of questions, I got a question we'll kick it off with for each of the presidents, and then we'll open it up to questions.
I'm gonna hit on things that are really some of our most frequently asked questions. Hopefully that'll be useful. We've got microphones that we will get around to anyone who has a question here in the audience. I'm going to start with natural gas. Thomas Martin, President of our gas group, as you know. Your base business has turned the corner in the past year. Now seeing some increased rates on renewals, what's driving that? How do you see demand for storage and transportation trending going forward?
Good question. I actually got that one on a few sidebars already, so I know a lot of you are interested in this one. As David noted in his presentation, this is the last year of meaningful unfavorable recontracting risk for the foreseeable future. As you recall, in past presentations, we've been showing you know, kind of the two prompt years of what that risk look like going forward. Although not material in the whole network perspective, it was material or meaningful for those particular assets involved. Those were primarily single-source supply pipes with point-to-point deliveries, no real demand associated with them, no customers directly connected. All of those have reset now.
Now the way to think about it is the rest of our network, for the most part, is an integrated supply and market network with direct users, end users at the end. As David noted in his presentation, the uplift on renewals, you know, now, slightly more than offset the last bit of unfavorable recontracting risk. That's evidence to what was mentioned earlier, that we're starting to see increasing values, longer terms on renewals for our transportation and storage services really that we didn't even see a year or two ago. I think there's some momentum building here.
As far as the fundamental drivers behind that, I think we've covered that a lot in the material, but it's the LNG export growth that we've seen, and that trend will continue for many years to come. In the midst of that, we're still seeing supportive demand in our power gen, industrial, and Mexico export businesses. The permitting and regulatory environment that we see in some parts of the country make it extremely difficult, if not impossible in many instances, to add new infrastructure. That's primarily outside of Texas and Louisiana. You know, as demand in the market overall grows, the value of existing infrastructure, both pipeline capacity and storage grows with that, with that growth.
The last thing I would say about Texas, even though we have a little more friendly environment to build our network, and last mile to connectivity and storage position in Texas gives us a unique advantage to, you know, extract value there and provide services that many of these greenfield new pipelines can't do in that market. Last thing, you know, we talked a lot about the intermittency of renewables. We see that trend start from the West Coast and heading towards the East Coast.
Every market that we've seen that go into, where we've seen 30% penetration or greater of intermittency, not only just on a regular day where you have such a huge drop-off of renewable, whether solar or wind, but then when you overlay that with weather events, whether it be extreme heat with no wind or extreme cold with no wind or solar, then you know, we've really seen the need for natural gas pipeline and storage capacity needed to backfill those demand needs.
You know, you stir all that up, I really feel very strong about the growth of our network, and not only for project opportunities, but I think base business, I see some green shoots in our base business values, both for transportation and storage, rates as well as term on our contracts.
All right. One quick follow-up from Thomas. Many of you know that on our EPNG system, we've had some repair and testing work that we've been doing on our Line 2000, and we have an update as of this morning on that. Thomas, why don't you cover that quickly as well?
We talked about this on the earnings call that we expected to be completed with our work and submitting our request to return to service to PHMSA. In fact, we have completed that work, and we submitted this morning that request to PHMSA. As we said before, it's gonna take them some time to digest that and evaluate how fulsome that all is. We feel good from the perspective of the work we've done, and we feel we've done well to meet the expectations and requirements of the CAO. We'll see how long that takes PHMSA, and we'll certainly give you an update when we learn more.
That update was posted on our El Paso E-EBB this morning. Next question for Dax Sanders, president of our products group, about the renewable diesel opportunity. How much potential is there to do additional RD beyond the two current California hub projects set to come online this year? How will expansion of RD supply impact your existing business?
Yeah. Good question on the RD front, and that's certainly something we've talked a decent bit about. You know, maybe starting with you know, level setting where we are right now, consistent with what Kim walked through, we've got right around $70 million worth of projects in our backlog right now related to renewable diesel. Now we talk about the two hubs in Northern and Southern California. Those are about $50 million of it. You know, we've got another, call it 20+ of, you know, what I would call other associated projects, tank conversions, ancillary services, things like that. We actually have, we've actually got a 100-year-old crude oil tank that we're converting to renewable diesel, if you can imagine that, in Los Angeles.
So that really is kinda where we are right now. Again, with our hub projects, they create about 40,000 barrels a day of RD capacity, and we've got take-or-pay contracts for about 31 right now on that. I think we'll probably end up terming up a little bit more of that. The balance of it, we will, we'll keep as spot capacity. You know, our ongoing dialogue suggests with customers that they're gonna want additional capacity, particularly as some of the domestic refining capacity conversions that are happening, you know, come online.
Certainly right now we've got bp Cherry Point up in the west, and then we've got both the Marathon and P 66 facilities in Northern California, which are, you know, in the Bay Area. Those are kind of a mix of producing a little bit of renewable diesel right now, as well as coming online with their full conversion projects. You know, as I've said in the past, right now, and as Kim said, all renewable diesel right now is gravitating towards California. It all wants to go there, and that all is a product of sort of the well-developed three-layer tax credit. You know, everybody gets the two layers from the federal perspective.
Then California, the LCFS that California has, makes it the most lucrative to go to California. There are other states, and particularly in the West, that are putting in place, you know, state credits that are starting to, I think, create a lot of interest for people. Oregon's probably, you know, the furthest along, that's creating additional interest. You know, Washington State has got one as well, probably not as, you know, still needs a little bit of developing. But, you know, the dialogue that we're having with our customers, you know, certainly is still centered on California, but we hope that...
Part of this has to do with availability of supply, because as you all know, you know, the supply is not as abundant as it probably will be at some point. Our customers, you know, have increasing interest in other areas. If you look at our footprint across the West, we've got a really good footprint across the entire Western United States. We, in addition to California, we've got a couple of terminals in Oregon, but, you know, in Nevada and Arizona, we supply the majority of refined products across the board to those states. To the extent that those states put in place, you know, similar type regimes that drive demand for it, I think we're really well positioned for that.
Just to put a finer point on, I think it's important to put a finer point on the value that we add. You know, with respect to renewable diesel, if you're blending 5% into the stream, you really don't need to do much beyond the point at which you blend it. Our customers blend the 5% in, and they get the tax credit. Above and beyond that, the concentration of it has to be tracked all the way to the fuel pump. You know, transporting any concentration above 5%, even up to R99, requires, you know, a lot of thoughtful handling and segregation of product, including interface in the pipeline.
That's really where we come in, is having the infrastructure to be able to track it and handle it all the way through and process the interface. You know, what we're able to do is charge a fee and earn an extra fee for segregating those volumes of maintaining the integrity of the stream and the tax credit. So anyway, we believe that, you know, we said a couple of years ago that we thought the opportunity set would be somewhere close to $100 million over the next couple of years. We're, you know, we're right on top of that.
You know, we certainly hope as supply becomes more available and our customers become more, you know, enthusiastic about renewable diesel in other places, that'll transcend to opportunity in other places.
All right. Very good. Going to the other end of the renewable fuels, liquid fuels, chain. John Schlosser, President of our Terminals Group, renewable feedstock hubs. How's the Neste project going?
Luckily a lot more good than bad in regards to this project. As Steve mentioned earlier, we have two of the 30 tanks came on this past Monday. The remaining 28 will be rolled in as the quarter progressed. The projects team has done an absolutely outstanding job managing supply chain issues, material cost pressures. We are showing an increased amount of spend on this, to $80 million from the original $65 million. Much of that increase is attributable to project scope additions and enhanced modal capabilities that the customer, Neste, specifically requests. The returns are very comparable to what we originally had discussed from a percentage standpoint. More so, and Kim alluded to these, though we're real pleased with the direct, it's really the indirect that has surprised us to the upside.
What were those? You know, the return is great, but we were able to, and we hypothesized that all ships would rise as we were able to attack this project at our 3 million barrel Harvey facility. We actually have performed significantly better than what we anticipated. As we're recontracting the existing customers, we've been able to, one, do it at a much higher rate, and two, do it for a much longer term from a year's standpoint. Just to give you a feel, and she alluded to this, you know, this facility was significantly challenged within our portfolio. We were trying to figure out what's it gonna be when it grows up. Historically, you were looking at less than one-year contracts.
Oftentimes, we saw utilization in the 60% and 70%, and rates were fairly compressed. What we've been able to do is high grade all of the existing customers there, push price up and get much more term on it, to the point now where we're looking at almost 100% utilization as soon as this project rolls into play. The knock-on effect, though, has been the projects that you see on the far right here. We saw opportunities to make additional investments on behalf of customers at Harvey and also to look at another feedstock hub at our Geismar River terminal north of Harvey. That project is with REG/Chevron, as was mentioned. Very good return under 10-year agreement.
It's clear to me that our customers value our ability to deliver on these, and we're seeing more projects come to fruition because of it.
You know, a couple years ago at this meeting, I mentioned the great bones of our assets. I was talking about the 75 terminals, the 78 million barrels, the 266 ship docks, 462 truck bays, et cetera, et cetera, et cetera. The reality is it's always easier to do a project when you're using some existing infrastructure than when you have to build it all greenfield. I believe, as Dax does, that there will be more projects like this, and we hope to replicate these in other parts of our network.
All right. As the Neste CEO told Dax and you and me and Mike Gwartney in a meeting, you can't electrify everything. You know, we're gonna need it for long-haul trucking, we're gonna need it for aviation. Good to be in this on both ends of that spectrum. Okay, Anthony, oil production outlook. Is it possible to continue extending out the productive life of your EOR fields?
Yeah. We've consistently been able to extend the life, the production horizon at our enhanced oil recovery fields. We do think there's also modest opportunity for future growth there as well. A lot of this is related to increased experience that we have with these mature fields and understanding of the geology. Also, utilization of innovative technology and processes, including advanced seismic. Certainly, more recently, the higher oil prices have helped as well, in creating more economic projects. We've had a great deal of success, I would say, especially in recently at SACROC with our development projects. This helped us beat our 2022 budget, net oil production by 5%.
We ended 2022 just under 2% lower than our 2021 levels, and we're budgeting for just about a 4% reduction in net oil production from 2022- 2023. So, you know, we've been able to manage declines at our fields, I think, to a very low number, low single-digit percentages. Good analog, I think, for this is what you're seeing on the screen right now, our SACROC project. Every year, we kinda show you our production forecast. Every year, we kinda manage to shift that out in time.
This year, not only are we shifting that production forecast out in time, you'll notice that the rate of decline there is much flatter as well. That's due to a lot of the efforts that the team's been making. As Kim mentioned, our other big field is at Yates. Yates has been producing oil for almost 100 years now, and its decline rate is less than 4%. We've got some great fields that continue to keep producing. As Steve mentioned earlier, you know, we do think there is a long runway for demand for oil and gas production, both in the U.S. and globally.
For the right economics, and just to be clear, that means, you know, returns which are well in excess of what we would target for our pipeline and terminals business, we are interested in new EOR opportunities, especially in light of the development of the CCUS market.
Also for you, Anthony, on the ETV business, how and over what timeframe can renewable natural gas and carbon capture and sequestration scale?
As Ken mentioned, we've made three acquisitions in the last 18 months, so we've been very active there. We have, we now believe a strong platform to grow off of. We have a good experienced management team with our Kinetrex folks. And really right now, our focus is on project execution as well as organic growth. We have 14 landfill biogas assets inclusive of the RNG plants that are under construction right now. That, we believe, puts us in a kind of, in a leadership position within still a very fragmented space. We've been able to achieve that at an attractive multiple. On the CCUS side, we've been talking obviously about the Red Cedar project today.
In general, though, we believe the development cycle for CCUS is gonna take longer. It's gonna take longer to ramp up that scale. That's some of the factors that Kim went over earlier. Longer permit timelines. There is newer technology that's being utilized in the capture space. Potentially you're going to be needing new pipeline infrastructure. The contractual arrangements can be quite complex to work through. With Red Cedar, we were able to expedite that process. It is utilizing our existing infrastructure in place, as well as because we are capturing CO2 off our natural gas processing facility, we're able to permanently sequester that CO2 in a Class II well.
That process is a much shorter process than the Class VI permitting process. We do think there are more opportunities behind Red Cedar to do something similar. They are, in general, smaller scale types of opportunities. When we think about our larger scale opportunities, those are centered around the Gulf Coast, some in the Midwest. Those will require us to be subject to the Class VI permitting timelines, as well as will require new infrastructure. Again, it will take a little bit longer to ramp up the scale in this business. We do think we are gonna be a leader in this space. We are the largest transporter of CO2 in North America.
We have been injecting CO2 in the ground, safely and efficiently for decades. As Kim mentioned, we can participate and have the flexibility to participate across the CC West Valley chain. We think we're a very attractive partner for folks out there.
Okay. All right. With that, if you've got a question, put your hand up, somebody will put a microphone in it, and we'll take questions from the floor here. Up here too. Here. Okay, somebody back there already has a microphone. Who does? There we go. Go ahead.
Hi. Can I go? Yeah. Neel Mitra, Bank of America. Had a question. You raised your expected exports to Mexico, the natural gas side from 7 BCF- 9 BCF a day. It seems like there's a lot of initial activity going on with West Coast LNG in Mexico. Could you see a path towards expanding parts of EPNG? On the other side of it, how are you looking at Agua Dulce and possible exports down the southeast side of Texas?
Very good. Thomas?
We, we are looking at opportunities to serve Mexico both for LNG exports and also industrial go-growth, actually even more near term opportunities there. I think there are some projects that we're pursuing or certainly looking at from a development perspective of EPNG on the U.S. side, working with potential partners in Mexico to serve those loads.
Then as far as, you know, Agua Dulce is concerned, I mean, certainly looking at opportunities to serve Mexico and any other markets, and even potentially on the U.S. side, to debottleneck what, you know, that area, as you've seen, the Permian projects that have been kind of moving towards that location, you know, certainly in need of demand, whether it go to Mexico or to LNG along the Gulf Coast, to debottleneck that area. We're, you know, actively working both of those opportunities.
Okay. Gabe?
Gabe Morin, Mizuho. I had a question on the Haynesville CapEx on the pipeline side. You had $265 million, I think, budget for this year. I'm just wondering, does that include everything, well connects and, you know, soup to nuts? Also bigger picture, where does that get you? Does that get you ahead of the production profile that you're expecting for the next year or two years, or is this the level of CapEx we should expect kind of year in, year out if it continues to ramp? Just bigger picture also, whether you'd ever consider kind of a long-haul egress pipeline over Haynesville and participating in a project like that?
Yeah. Good question. The $265 really does cover, you know, all of our needs for 2023, including well connects and all associated, you know, expansions on our KinderHawk asset in the Haynesville. Yet to be told as to, or seen yet as to whether we need additional capability. You know, we're in active discussions with customers in that basin to attach additional volumes. Don't think it will necessarily in 2024 be of that scale, but we certainly are looking at other opportunities to potentially bring additional volumes onto KinderHawk even after 2023 as those long, you know, as that market continues to grow.
To your other question, yes, we're, you know, nothing imminent, but we are certainly working up egress opportunities from the Haynesville down towards the Gulf Coast, both from a greenfield perspective and looking at are there ways that we can expand, you know, our footprint, whether it be TGP, NGPL, SNG, to take on more transmission volumes from that basin. We do have some underutilized capacity on TGP, which, you know, certainly is benefiting from the growth there and expect that to continue. Certainly as contracts come up for renewals on those assets, we would expect, you know, better values on those as they come up, even if we're not able to deploy any additional capital there.
Okay. Brian, always Brian.
Hi, good morning, Brian Reynolds from UBS. Maybe just start off on the Permian growth expectations of 10 Bcf by 2030 and the 9 Bcf per day of LNG supply that Kinder is pursuing. Maybe just in the context of capital allocation and the $1 billion-$2 billion of growth CapEx run rate, you know, how should we think about that, you know, going forward? Could that move up? How do we ultimately think about the $4 billion in balance sheet capacity to help support some of those maybe perhaps larger growth projects going forward? Thanks.
Thomas, why don't you start, and then David, if you want to add.
Yeah, I mean, I think from a business unit perspective, we're, our job is to bring the best, highest returning, most actionable projects that we can to the leadership, and we will certainly continue to do that. I think, what I believe whenever... From my experience with the company over about 20 years here, whenever we found good opportunities to execute at great returns, we find a way to do it, whether it, you know, fits within the $1 billion-$2 billion a year, or we find partners that we wanna work with to help get the project executed. I'm not as worried about capital capability there. We usually find a way to execute well when the opportunities avail themselves that have attractive returns.
Yeah.
In terms of our annual capabilities of funding, we're at the $2 billion or even a little bit north of it, given some of the growth expectation beyond 2023 that we have baked into our longer term forecasts. I think we have some additional capacity that we're gonna generate. Even if we're a little bit north of the $2 billion on the high end of the growth capital budget range that Kim mentioned, I think we should be able to fund that mostly or entirely with cash flow from operations. To Thomas's point, should we have greater opportunities than that that meet our investment criteria? We've been able to find a way to fund those, and we think that is in the best interest of our shareholders.
Should we have greater opportunities than what we can fund internally, it is in the shareholders' best interest for us to find a way to accommodate those.
I'd also say you've got some room. If you look on slide 40 at the backlog, and we're showing 22% of the projects coming in in 2024, you know, that'd be about $725 million of capital. Some of that capital will get spent in advance of that. You'll also be spending some capital on 2025 projects, but you've only got 16% coming in in 2025. We have room to, you know, potentially add to the backlog before you even get to $1 billion, likely. Significant room, I think, to get to the $2 billion.
Okay. Yves?
Thanks. Yves Siegel Asset Management Partners. When you look at the potential for the LNG export market, do you think all of the required gas will come from Permian and Haynesville? Or do you think that we'll need Appalachia gas to satisfy the export market?
John?
Yeah, that's a great question. I mean, I think the market would like to have more down from Marcellus Utica. You know, again, the permitting and the regulatory challenges with if not almost impossibility, unfortunately, at this point, of making that happen makes that challenge. I think, you know, if you just look at where the growth is, as Kim noted earlier, you know, that's one of the three, right? I think to meet the growing demand, you know, we will need something extra out of Marcellus Utica in addition to the Permian and the Haynesville. Eagle Ford is growing as well. It's only a BCF in those forecasts.
I think given the proximity to the Gulf Coast, you know, maybe that number's a little low, maybe it could be more, especially when you think about the Lean Eagle Ford. We'll see. We, we definitely need more than the Permian, the Haynesville, I think, to support all this.
Hi, good morning, Marc Solecitto with Barclays. As you think about the economic rent across the energy value chain with as intermittent power sources gain market share, do you see storage potentially being one area for midstream operators to augment their share of the economic rent over time? You mentioned storage rates are currently below new build economics. Wondering if you could talk about the competitive advantages of your existing storage footprint and various entries rates maybe start to move closer to new build economics?
Yeah. Yeah. Both really good points. I mean, I do think we're seeing that correlation become pretty high right now, where, as we become more and more of an intermittent market on the power side, the need for gas storage to back it up, certainly in the, you know, near term, intermediate term, and I would argue even longer than that utilization is increasing both from pipe and storage perspective and the value of what we're getting and seeing both on a short-term optimization perspective as well as people interested in term commitments. We're seeing, you know, really good values there.
I think we will get to, you know, if you just think about it holistically, how much, you know, Kim talked about it earlier, how much the gas market overall has grown, both supply and demand, but we've added very little storage capacity, and the nature of the market has evolved from more of a base load to more of an intermittent market. We have to get to places where we can price storage at greenfield development rates. We're not quite there, but we're getting there. I think that's where the market will need to get to. I think that means, you know, more salt dome capability, more, you know, high cycle capability, particularly along the Texas, Louisiana Gulf Coast. I think we have a great position there for us.
I would just add, Thomas, do you agree that to some extent too, we need power markets to be reformed so that generators can get paid and compensated for holding that capacity? I think that's part of what needs to happen in order to enable that. Vicki, next to you here.
Hi, Keith Stanley with Wolfe Research. I had two questions. First on the G&A, David, you know, you're up over $100 million on the pension expense year-over-year. If you have normal asset returns from here and discount rates hold, is that increase in G&A a run rate now, or could that reverse out in 2024? On the volume side, so gas gathering, crude, refined products, the growth rates are all higher for this year than they were last year. Is that what your producers are telling you right now, or just any color on the volume outlook? Thanks.
All right. On the pension accounting is a bit beyond me, but I'll try to weigh in as best I can. I think that there's going to be a little bit of a run rate here because our assets did decline so much in 2022. It depends on the performance of our assets and our continued funding of cash contributions to the pension plan. The year-over-year impact is clearly outsized this year as versus going forward. I think because we're at a lower starting point now with our assets, you're gonna have a little bit more of a reduction in the earnings that we are making on those assets because we're starting at a lower level.
That, depending on the asset performance, is a little bit more of a run rate. There's a lot more of a complex calculation to it, but I'll just leave it at that, and we can follow up afterwards after I've had some time to consult with our pension experts.
Okay. Yeah. On GP volumes, yeah, I mean, I think clearly we're very, very close relationship with our producers to get insight as to what their well connection activity is and timing of that activity. You know, what level of, you know, rig commitments they've made. Not really just relying on what they tell us, but we also have some insight into what they're actually doing. That's the basis of what we have baked into 2023.
Yeah. Dax, did you wanna add anything on the crude side?
Yeah. I think you mentioned crude. You know, crude volumes across the board are, we're looking at, up 8%. I think looking at where those come from, you know, the biggest increase is on KMCC, couple things there. We are in pretty good contact with our customers. We have one legacy customer that we're in the process of renegotiating an agreement with, that we've got some pretty good transparency into. We also have an intercompany marketing affiliate that uses some of that capacity that does low risk buy-sell type transactions. We've got some pretty good transparency into that. That's it on KMCC. Highland Crude is the second, probably largest increase. We're up about 4.5% on that.
We're really just getting back to, you know, we're right around just north of 200,000 barrels a day, getting back to 21 levels on that asset. You know, remember we had a pretty large winter storm in April that affected that asset. We had two more of those in December. You know, I think we had roughly 120 well connects in 2022, which is less than we anticipated. We had 23 wells that we thought were gonna come on in December that pushed forward, and our budget for this year is 120, basically flat. That's before taking into account the wells that pushed forward.
That, you know, we feel, you know, we feel pretty good about that. Double Eagle is a small asset, but it's actually got some pretty good increase associated with a customer that's shown some interest late in the year. The one that has a little bit of the one asset that probably has a bit of risk to it is Double H. You know, basis differentials out of the basin into Casper or Guernsey and in Cushing are still negative. We've got some risk of that. Across the board, I think we've got pretty good connectivity with our shippers and feel pretty good about it.
Okay. I think.
Refined products.
Yeah. Refined products. You know, I think as Kim mentioned, we're looking at overall across the board just over 3% growth from the previous year. I think as I mentioned on the call, you know, it's not a massive factor, but we had one of our major lines down in December for quite a few days that cost us a lot of volumes that, you know, affected the Q4 quite a bit. Gasoline, the increase in gasoline is just over 1%. A larger increase is with diesel and jet fuel. Recall, you know, Kim mentioned the opening of international flights. Recall where we were compared to the EIA, we were trailing.
You know, I think we are still 14% below 2019 levels on jet fuel compared to the EIA at -10. We are assuming that we will make up some of that ground on jet fuel. As she also mentioned, we've got the renewable diesel projects coming online with 31 a day of take or pay contracts associated with that we think will augment the diesel volumes.
Okay. We've already started, but feel free. We'll open it up to questions for anyone here. Yes, sir.
Hi, it's Paul Sankey with Sankey Research. Richard, over a decade ago, you told me that the return on a stock is just the dividend plus the dividend growth. I just wondered, with a relatively modest outlook for growth in the dividend this year, whether perhaps you would consider stepping up perhaps the buyback. We've said that one thing to keep in mind is that you're now competing with E&P companies, which historically really haven't paid any dividend at all, and that we felt that companies would have to get to a 10% cash return annually to be attractive against any stock in the market. If you were to add, say, a couple of percent of buyback, you would get there.
I think especially in the context of what's happening in Europe, and particularly regarding obviously Russia, the outlook seems to me to be outrageously bullish for what you do, assuming you just, for example, maintain market share in LNG exports. Is there a potential here for you to upgrade how much cash you return? Thanks.
Well, that's a very good question. This is something the board spends a lot of time on, and we're trying to balance all these priorities. But certainly, we look to continue to increase the dividend. The question is how much per year do you increase it? As I look ahead, as I said earlier, we certainly anticipate continuing to increase it, relatively modestly, but we will continue to look at that. What we look at is how much cash can we really return to our shareholders while still maintaining a very healthy balance sheet, which I think we have, and still maintaining a level of capital expenditures where we're taking advantage of these really pretty extraordinary opportunities that you see in the 23 capital budget.
When you can do these kind of things at this kind of EBITDA multiple, you'd be remiss not to pursue them. This is something we examine on a continuing basis at the board level, and we certainly are committed to maintaining a strong dividend. Your idea of the 10% overall return is something we've certainly discussed, and we'll continue to look at.
Thank you.
Okay. Richardson, then Lisa again.
Afternoon. Tristan Richardson at Scotiabank. Just Tom, perhaps the obligatory Permian egress question here. Certainly the basin will see some relief in the fourth quarter. But we've also heard some vocal producer commentary about GORs and perhaps a need for additional egress on almost on a programmatic basis, whether that's every two years, et cetera. Can you talk about how commercial discussions sound today versus, say, two years ago while PHP was being contracted and built? Secondarily, can you talk about just the input cost environment today versus, say, 2019 or 2020 when PHP was first being built?
Yeah. No, both good questions. You know, I think help is on the way is sort of the conversations that we've had today as far as the projects that are going into service, you know, this year and next. I think, as you say, there's certainly, you know, a need that we're hearing from our customers somewhere in the 2026- 2027 timeframe, early 2027 timeframe that could, you know, move up or push back a little bit just, you know, as we further those conversations. The other part of that dynamic is, you know, Mexico needs for LNG export as well as other needs and how does that weigh into sort of debottlenecking the Permian as well. You know, definitely active conversations on that.
Certainly when we get customers to the table who are ready to make the kind of commitments that we need to support, you know, a significant project, we'll bring that forward. Nothing imminent yet, but a lot of good discussions. As far as costs, I mean, clearly that's a factor, right? I mean, if you looked at the tariffs and rates that we saw on the first projects versus what it takes now to do the same kind of a project now, as and factor in, you know, the desire of some of the customers wanting to diversify where they go with their molecules, that even adds more costs as you go east.
Again, that all weighs into the appetite for making the kind of commitments that would be necessary to sponsor a new project.
Okay, Gabe and then Gina.
Okay. Gabe Moreen, Mizuho. Two follow-ups for Anthony, if I could. One is, you mentioned the flattening on the SACROC profile. I noticed the 10-year development CapEx for SACROC this year versus last year seemed to have increased. I'm just wondering maybe what the some of the drivers were behind that, whether it's cost inflation, getting more aggressive on flattening things out. The second is on sort of the marketed versus the D3 market in the RNG side of things. I'm just wondering how aggressively you're pursuing bilateral contracts. I get that the returns now on RNG are pretty gaudy with where the RINs are, it seems more prudent, Kinder Morgan, ask to do the 10-year contracts, even if the returns may be a little bit lower.
Yeah. First on the SACROC question. Yeah, part of that is a function of the oil price environment and basically the forward curve there, which has made a lot more projects economic. So we were able to turn on some inactive wells effectively there. So that's part of this, the answer. Part of the answer, as I was talking about before, is really, we know we've learnt a lot more about some of the, I guess, more fringe parts of SACROC, and got more confidence in the productivity on those projects. Part of that is related to the recent success we've had with our development projects there. On the RNG question.
We've got four projects currently under construction. I would say three of them are really dedicated already. They're contractually dedicated into the transportation market. We are going to be generating rents there. The fourth project we just FID was Autumn Hills. We're in active discussions with numerous counterparties on potential long-term fixed rate contracts. It, I'd say there's a increasing amount of interest from the voluntary market, and prices aren't on dropping there. They're only going up in that space. I think we've got some good opportunities to diversify away from the transportation market.
Okay.
Hi, Jean Ann Salisbury from Bernstein. I think my question's for Thomas. I wanted to follow up on the commentary around being able to recontract pipelines over time to higher rates. Is there any way to put goalposts on how much of your volume or how much of your EBITDA might be able to recontract up to higher rates? Is the right way to think about it, how much is cost of service versus negotiated rate?
Yeah, I don't have that for you today, but I think just if you think about it in the context of, you know, everything from the Midwest east, it seems to be where we're getting the most traction. To the extent that we can do negotiated rates, that's certainly where we can maintain that value over the long term. We do see more opportunities to do that than we certainly have in any time in my history with the company in this sector. You know, I think just the trend line there is good. There are ways to, you know, sort of manage that regulatory risk as you go forward, and that's certainly part of our strategy.
Okay. Any more questions?
Okay. Well, thank you all. We do have lunch set up and next door? Yeah, next door. I believe there's assigned seating so that we've got people... Is that right, Peter?
For.
Okay. All right. For the business unit presidents. I wanted to say thank you to everybody who worked on this. All the business unit presidents, certainly, but a lot of people who Kinder Morgan people who you see here worked on this very hard. I think Pete and Sean maybe got part of Christmas Day off. Really appreciate all the work that everybody's done. Thank you for coming and being here in person. Thank you all.