Good morning, everyone, and thanks for joining us. I'm joined today by Steven J. Kean, CEO, and Anthony Ashley, Treasurer and VP of Investor Relations for Kinder Morgan. Before we get started, I want to make you aware of the fact that you can ask questions during this session. You can do so by emailing me directly at michael.j.blum@wellsfargo.com, and I will ask your questions to management during the session. With that, let's begin. Steve, Anthony, welcome. Thanks for doing this. I'm going to turn it over to you, Steve, for some opening remarks.
Okay. Thank you, Michael. Look, as you saw and as you wrote about yesterday, we issued our 2021 guidance before market open yesterday. You can see our capital allocation priorities clearly on display. Our capital discipline, as well as the cost savings initiatives that we undertook over the course of the year, and our reorganization has set us up nicely with $1.2 billion of additional cash flow that we can use in excess of our discretionary capital and dividends that is available to strengthen our balance sheet and repurchase shares in a program of up to $450 million, which we expect to use on an opportunistic basis. As we talked about for many years, we've been self-funding since 2015. By the end of the year, we'll have reduced about $11 billion in debt, including another $1 billion this year. We've taken care of our balance sheet.
We've allocated capital to the projects that provide attractive returns to us. Beyond that, we use our excess cash to return value to shareholders. We're doing that with a good dividend, which we increased by 3% for 2021, but also maintaining, and I think this is good in times like these, maintaining flexibility in how we return value to our shareholders. We allocated, or put the weight more toward, share repurchases, which we, again, would expect to do on an opportunistic basis. Our decisions there will be driven by what returns we see from share repurchases. Strong balance sheet, investing in attractive return projects with a good margin for safety above our cost of capital, then returning the excess cash that we generate to our shareholders.
While we did show a slight decline in DCF year-over-year with part of that due to contract roll-offs. We project every year in our January investor conference, we show what we expect for the next couple of years of that exposure to be. 2021 was a bigger exposure year as we showed in both our January 2019 investor day as well as in our January 2020 investor day. From here, we have some additional exposure in 2022. Over the medium and long term, we see our natural gas business providing a good tailwind for us, our other businesses providing good stability in terms of refined products, particularly in a post-pandemic world. Our CO2 business, which is just now down to 9% or so of our segment earnings, more dependent on commodity prices.
As we do every year, we'll go into greater detail on our 2021 budget when we do our investor day in late January. That's the overview on our guidance, Michael.
Great. Thanks for that. Appreciate it. I had a few follow-ups to that. Maybe just to start, just wanted to understand a little bit better some of the puts and takes. Specifically, you mentioned the recontracting headwind. How meaningful was that? Where does recontracting stand on FEP and Ruby right now? It sounds like after 2022, those headwinds sort of fall away. Would you expect that at that point, you will start to see EBITDA grow?
Yeah. As we said in the release, we have the recontracting headwinds, and this is associated with projects that were built a decade or so ago under long-term contracts. With those contracts rolling off on those particular assets in a more challenged basis environment. The basis differentials having just completely come in, if not collapsed on those two assets. Then we also have with a $43 price expectation on WTI, lower volumes in our CO2 business and lower realized pricing in our CO2 business. Then with lower capital investments, a little bit of a reduction also in overhead that was previously allocated to projects and capitalized. Those are the big moving pieces. Overall, on FEP and Ruby, those are challenged assets, just no question about it. FEP has another pipe in the ditch, essentially, a Boardwalk Pipeline.
Fayetteville, if there's not $4-5 gas prices, it's hard to imagine additional drilling in the Fayetteville Shale that would help bolster prospects for that asset. It's a challenged basis environment as the remaining contracts roll off as well, which we'll see in 2022. Ruby, similarly. I think on Ruby, while the basis is not good from the Rockies, there's plenty of Rockies gas egress, more capacity there than there is production. Ruby has proven itself to be valuable to our customers from a reliability standpoint. When we saw outages on Northwest Pipeline earlier in the year, we saw good polls on Ruby, and I think that reaffirmed its value to our downstream customers, and in fact, went through the PG&E bankruptcy proceeding with that contract affirmed.
It has some value there, but it is a challenged asset for sure on contract renewal. Really on longer term basis, what needs to happen for Ruby to have value is Jordan Cove LNG needs to get developed and built and probably even expanded, even like a phase two of Jordan Cove. We're a good way away from that, I think right now. It's maybe on the horizon eventually, but those two assets unquestionably are challenged. Now, on the other hand, we have the biggest and best natural gas pipeline and storage network in the U.S. Second to none. Natural gas demand continues to grow. Exports are at record levels. LNG continues to come online. Mexico has taken five BCF a day plus. We're well connected there.
We are connected to, on our networked pipes, we are connected and integrated with our downstream utility customers, end users, power plants, et cetera, and it's hard to build, as you know, new infrastructure. We got our PHP pipeline built in Texas in the face of considerable operating issues, and we've got all that pipe in the ground, but it's not easy, and that tends to increase the value of the existing network. Expanding supply and demand tends to increase the demand for our infrastructure as well. Over the medium to longer term, as I said, we like the overall picture for natural gas and the use of our infrastructure there.
I would say that's true, including with increased renewable penetration, because what we found in our California markets in particular, is the more renewable you put into the generation stack, the more demand there is for what we do, which is less about the commodity than it is about providing the capacity, storage, and transportation when it's needed. It gets needed more. As we saw this summer in California, the demand for the peak availability, the deliverability that we provide, and that's how we market our services in California and other places where renewables are penetrating. The more you put renewables in, the more your demand for what we do on a peak goes up. If you need us some hours every day, we can sell you capacity the whole month and the whole year.
I think all those things are positive tailwinds for our natural gas business, which is 60%+, 62%, I believe, of our segment EBITDA, and it's 74%, almost three-quarters of our backlog.
Great. That was very helpful. Thank you. Another question on guidance, just to clarify, first of all, the $450 million of buybacks, you said that's opportunistic, but will you exhaust that through the year, just you don't know when, or you may or may not, depending upon market conditions? I guess that's the first question, and the second part of that is just how you've thought about balancing dividend growth versus buybacks. Why not just hold the dividend flat given where your yield is and just do all buybacks, and just sort of the thought process on how you balance the two and how much the stock price and the yield plays into that decision-making.
Okay. On your first question, it's a may or may not, right? We'll use the capacity if we see the value there. It's not programmatic, it's opportunistic. We are not telegraphing at what price we'll purchase. We've certainly talked to our board about different scenarios there. We do it on a return basis or an expected return basis. That's a function of the price at which we buy it, whether or not there's any multiple expansion over the longer term. Under various scenarios, you can see some pretty attractive levered return opportunities, particularly when you see yield if we find ourselves yielding 8% again or something, right? There's the opportunity to do it, but not the commitment to spend it. We can leave it on the balance sheet and save it for another day, et cetera. It's a may or may not thing.
In terms of the thinking on the allocation, as you know, Michael, there's more flexibility. We think of our dividend as a fixed obligation. If we were going to increase the dividend further, that's a fixed obligation. There's less flexibility in terms of how we return value to our shareholders. Having more of it allocated to share repurchases seem like the right call. In terms of why not just be flat? Yeah, there's an argument for that, for sure. Because it's even more flexibility. We thought, look, we've got the capacity to increase the dividend further than we did. We thought that increasing the dividend a bit, that's a return of value to shareholders that they can clearly count on. A modest dividend increase, but an increase rather than keeping it flat.
As we discussed it with our board, we thought that that was the right call. It's a well-covered dividend, even with the 3% increase, and it gives us plenty of leftover capacity to do share repurchases. If we see a turnaround, which we're not expecting or projecting, but if we see a big turnaround happening this year in our sector, we can use it for capital opportunities as well.
Great. One more question I had on the guidance, which was the growth CapEx of $800 million. Should we think of that as the low, the bottom, that's effectively a sustaining level that assuming you don't have any significant projects in the future, that's going to be a run rate?
Yeah. It's hard to know. That really depends on what kind of recovery we see in U.S. energy and when we see it. If you look back to 2015 and 2016, the rig count fell way off and production started to come down. It notched down. We're seeing that again. In fact, if you plot the two against each other, it's actually faster and deeper. Not deeper, but it's faster this time in terms of how quickly the rig count came down. The difference between the two-- then it came right back up, right? It came right back up and we set new records for production in 2019, and even the first quarter of 2020. It just really roared back in the shales. The biggest difference between then and now, biggest difference is there's a massive amount of OPEC+ capacity that's still offline.
Even with them going another half a million barrels, they're still north of 7 million barrels offline. That doesn't get soaked up until you see the natural decline rates of the conventional around the world resource plays come into play, and then a recovery in global demand. There's a lot more excess capacity sitting out there. The second big difference is the capital markets were all about the shales in 2017 and coming back into it. There was plenty of capital available there, and so they just roared back, as I said. That isn't going to happen this time. You have a bunch of producers who are a lot more disciplined in how they're going to deploy their capital. They're focusing on free cash flow. It's a longer, slower recovery, but it is a recovery. I think the recovery will be there.
We will see people returning to the shales. Our long-term projections as well as third-party projections, credible third-party projections, show us exceeding the 2019 and Q1 2020 U.S. production, just taking longer to get there. Once we get there, then you start to fill up the infrastructure that's been built and you start to drive the need for additional capital expansions. Now, to use us specifically as an example there, in Q1 of 2020, we were in active conversations with producers about a Permian Pass Pipeline, another Permian egress for associated gas, and we were in some fairly advanced discussions with some of those producers. Well, that's all off the table now. We pushed that out to the right, but we still think it's needed, but it takes until, call it mid-decade, for it to be needed. That's what will drive our capital budget, okay?
To try to get to a more specific answer to your question, Michael, we talked about $2 -3 billion for more than a decade. $2 -3 billion was our run rate on expansion opportunities. We started telegraphing this year. You know, that longer range outlook is probably more like $1 -2 billion with all the infrastructure that's been built and probably at the low end of that range for the next couple of years, and that's what you're seeing here. I know we were lower than what you were projecting, lower probably than we thought earlier in the year at $800 million. I think you're looking at something in the kind of billion-dollar range, really, for the next 2-3 years. It really is recovery dependent on seeing us get into the $1 -2 billion.
It's hard to see with all the infrastructure that's been built and with the difficulty of building new infrastructure, new pipeline infrastructure in the U.S. I would just project or speculate that it's hard to see getting back to that $2 -3 billion range really anytime soon.
Great. While you were talking, a bunch of questions came in from investors, so I'm just going to start going through them here and try to get to as many as we can in the time that we have. The first one was just a question effectively asking for an update on Permian Highway, where that stands, and maybe I'd throw onto that, in light of your comments you just made, when do you envision the need for another gas pipeline out of the Permian, or maybe not ever?
Okay. Yeah. Permian Highway. Look, I will just brag on our team and on our company a little bit here, if you'll indulge me. We built the Permian Highway Pipeline. We built it in the face of opposition, in the face of litigation, in the face of an uncertain permitting environment where Nationwide Permit 12 was in suspension for a while. Not for us. We were never forced to stop construction. We don't need Nationwide Permit 12 once we're in operation. We got through all of that, and oh, by the way, a pandemic too, right? We've got that. All the pipe is in the ground. It's full of gas. It's delivering gas today. We're in the commissioning process, meaning that we had a number of compressor stations. It's not just the pipe, it's putting the compression in place, et cetera.
Number of compressor stations that we are commissioning right now. We just got our 311 authorization. That's the authorization that enables us to move interstate gas through an intrastate pipeline. In addition, we can add. Now, the supply and demand from the interstate market can start serving that as well. We still expect to be fully in service early in 2021. On track there, and really a tremendous accomplishment. Look, there are several ways that we're trying to distinguish ourselves as a company. One is on our ESG performance, which I'm sure we'll get into also. Also on our ability to get projects built in typical circumstances. We've proven that with PHP. We're proving that to our partners, proving it to our customers and our investors.
It was really a tremendous effort by the whole organization, working together to get it done. Very proud of what we accomplished there and what we're demonstrating to the market by getting it done. As I said, just a couple of minutes ago, the Permian takeaway problem on natural gas, which was a big problem, coming into the year, has now been solved, particularly when you throw Whistler in there, coming into service. One thing I should have mentioned too, part of what we had to do with these two big Permian pipelines coming into our network, a five BCF a day network, call it, on the Texas Gulf Coast or our intrastate system, with four BCF of gas coming on, another two BCF from Whistler. Some of the Whistler gas will hit us as well.
We did need to do some debottlenecking, and so we had what we called our Crossover II project, which was a debottlenecking project on our Texas intrastate system downstream of the input from the Permian Highway Pipeline project. We subscribe that to end-use customers, and that is now in service also. That project was completed on time and in time for the Permian Highway Pipeline gas to come in. Now, Permian gas takeaway was a big problem because with all the oil-directed drilling, essentially gas was a waste product. I mean, it was being burned. It's still being burned a little bit, flared a little bit in West Texas. People just needed to find egress for the gas to get something for it. That was a real strong producer push project, or producer push demand for infrastructure.
That is gonna be taken care of here with the two pipelines that are coming on, ours as well as Whistler's. We don't see it in our own projections. We don't see it coming back into a constrained mode again until the middle of the decade. 2025, 2026. You'd think about starting to have discussions with producers in 2023 or 2024 to serve that need.
Great. Couple questions coming in from investors. One, this is kind of a two-part question. Does Ruby or EPNG have a role in transporting renewables in California? Second question, do you expect PG&E to renew or extend its Ruby contract beyond 2026?
Okay. I'm sorry. The first part of that was, does Ruby and EPNG have a role in serving the California market? Is that what you said? You cut out there.
Yeah. In transporting renewables in California.
In transporting renewables. Okay. Yeah. Yeah, on that, we do transport some renewable natural gas today, including on EPNG, I believe. That's essentially, that's been around for a long time. I mean, it's basically capturing landfill gas and transporting it. It's the same once it's been treated and cleaned up. It's the same as regular produced methane. We can transport it on our pipelines, and we do. Yeah, there's a role to do more of that. I think, the bigger role on that front is what people have called Responsibly sourced gas or Responsible natural gas. That is more about transporting, storing, producing, and distributing natural gas at a very low level of methane emissions.
We're part of an organization called ONE Future that has as its goal, 1% or less methane emission throughout the entire cycle from production, transmission, and distribution, by 2025. The transportation and storage allocation of that, our sector allocation of that, is 0.31%. We are currently, we've run between 0.02% and 0.04%. I think in our latest report, we were at 0.03%, so one-tenth of the target and seven years early, seven years ahead of schedule. The organization itself, ONE Future, met the target in 2018. The members of ONE Future, Southwest Gas, others met the target in 2018, so seven years ahead of schedule for the whole group. I think that that has some real promise, and we are talking to our customers about that today. I personally had conversations with some of our utility customer CEOs about it.
It is something that is of interest. There's only been, to our knowledge, four transactions that have been done on that basis to date by utilities. I think there is more of that to come. Particularly utilities that are going through rehabilitation programs to replace cast iron pipe, and they have significant fugitive methane emissions. We give them a lot of headroom. At 0.03% on our 0.31% target, we give them a lot of headroom for that. I think that that is something across our system, not just EPNG, and potentially Ruby, that we can do. EPNG also played a very significant role in this last summer, backstopping the California grid when renewables were not producing.
I think that was a bit, frankly, of a wake-up call on the importance of natural gas and natural gas generation to not just our customers, but also the policymakers in the state. If you think about renewables and the role we can play there, backstopping the grid is number one, and that's real, and it's there today. renewable natural gas is there today, but it's small. It's quite small. Could get bigger as time goes on. responsibly sourced gas, about 10% of the gas we estimate that moves on the grid today is responsibly sourced and we're one of those participants, and that's something that I think is an opportunity that's right in front of us. I'm sorry, the second part of the question was on renewal or extension. Tell me the second part of the question again, Michael.
Sure. Do you expect PG&E to-
Oh, PG&E, right.
Yeah.
Yeah. They have a longer-term contract on Ruby, and they have some step-down rights. We think, particularly since we went through the bankruptcy proceeding and they affirmed that contract, we think they'll be there for it. I think beyond their contract term, Anthony, you may know more about this in terms of any extension beyond 2026. Beyond their contract term, I'll tell you this. I think that they did see the benefit of having Ruby capacity when we had the outages on a third-party Northwest Pipeline. They saw the reliability advantages of having that. They do have a requirement under the regulatory regime in California of holding upstream capacity, meaning not just purchasing at the city gate or at the entry to their transmission system.
Those things kind of work in Ruby's favor a little bit, but we haven't had any conversations, and I wouldn't want to imply that we've had any conversations with them about extending at this point. Anthony, anything you want to add?
No, only that they would obviously need to go through and get CPUC approval for that. Having exited bankruptcy, I'm not sure that's something that they would do in the near term.
In the near term. Correct. Yeah. Okay. All right, Michael, we're getting a little low on time, so you prioritize us from here, and I'll try to be shorter.
No problem. I got a couple more questions from investors. These will probably be the last one, so I'll put them together. These are about the guidance. Can you provide more detail behind the $800 million of growth CapEx? Second question, how much normalization in refined product demand is assumed in your 2021 budget?
Okay. Yeah. Mostly natural gas. We'll give you more detail and breakdown in the budget review that we do in January. We're at that time of the year where we give our guidance, and then we tell everybody, we'll give you more detail in January, right? That's the basic answer. On refined products volumes, we do assume recovery, but we don't assume recovery to 2019 levels. We assume more recovery, obviously, on road fuels than we do on jet. Jet's about 8% of our refined products businesses. That's terminals and products together. About 8% of our refined products businesses segment EBITDA. We assume less recovery on jet, more on road fuel, but not back to 2019 levels. More details in January.
All right. That's probably a good place to hold it there. I'm going to thank you for taking the time with us this morning, and hopefully we're going to do this live next year in New York. That's my hope. Thanks for being on with us today. I appreciate it.
Thank you. Look forward to seeing you in New York.
Be well.