The Williams Companies, Inc. (WMB) Earnings Call Transcript & Summary

Good morning, everyone. We're going to get started here. I know that some people are still coming in. But in the interest of time, we'll try to get show going here, because there are people that will be joining us virtually. So I'm Danilo Juvane, Vice President of Investor Relations and ESG. Again, thank you for joining us. And of course, thanks for those who have joined us virtually as well. Definitely great to have people continue to come here after a couple of years of not being able to doing this because of the pandemic. Presenting from Williams today will be, our President and CEO, Alan Armstrong; our Chief Operating Officer, Micheal Dunn; our Chief Financial Officer, John Porter; and our Executive Vice President of Corporate and Strategic Development, Chad Zamarin. During a Q&A session, we will also be joined by our -- the rest of our executive team, and that will comprise of Lane Wilson, our General Counsel; and Debbie Cowan, our Chief Human Resources Officer. As you can see from our agenda this morning, we have a lot to cover with you. And we will power through the entire presentation prior to getting to the Q&A session at the end. Finally, in our presentation materials, you'll find disclaimers related to forward-looking statements. The disclaimer is important and integral to our remarks, and you should review it. So with that, we'll get our show started here. [Presentation]

Well, good morning, everyone. It's great to see everybody here this morning. And I'll just give you a really good piece of advice. Don't shake my hand this morning. I contracted a stomach bug yesterday. So I'm going to keep my distance from you and you'll do yourself a favor keeping your distance. But it really is great to have everybody here this morning. We've got a great story to tell, and I really look forward to doing that. And I apologize for not being able to spend some time with you socially. But I'll assure you that, that's to your benefit this morning. So first of all, I just want to get into an overview here of what we're going to talk about today, and these are the topics. It's really about the golden age of natural gas, as we mentioned. And I'm going to go through today some things that you've probably heard before, but I'm going to put some more specific examples around it and make it come to life for you a little bit, both in terms of what a powerful tool natural gas is, and what it's going to mean to electrification within the U.S. as well as the amount of -- a great amount of resources and supplies that we have in the U.S., low-cost supplies actually and then talking about how that is really continuing to drive tremendous growth here at Williams. And we, at Williams, really do. We have the right infrastructure, we have the right platform and we have the right strategy to predictably grow our earnings well into the next decade. And I think after you see the team's presentation today, you'll agree with me on that. So first of all, I'm going to really talk about some powerful statistics here around natural gas and what it's done already and what it can still do and the power of being that. And I will just tell you, you hear a lot of rhetoric. But at the end of the day, it's really hard to escape the facts. And as we continue to press towards energy security and affordability, natural gas is going to be turned to more and more and more, because we've really left ourselves with not very many options, frankly, in terms of the road that we've gone down to date. So this is a -- you've seen this slide before, showing the '05 to '21 reduction in power-generation emissions. And you can see here that power-generation emissions were cut by 1/3 from 2005 to '21, and that was about 867 million tons of emissions reduction. And so that's a big number. But importantly, 60% of that or 500 million tons actually came directly off the backs of natural gas. That is cold, hard facts. That's not disputed. That is what it is. And so just to put that in context, as everybody hears these numbers, and nobody ever knows what that really means, put that in context, that's about as many as there are light-duty vehicles on the road. That's the equivalent of taking those off. And of course, that is a lot more powerful at emissions reduction than converting those to EV because we still have to power those EV. That's an absolute 500 million tons of emission reduction that we've gotten today. So you might think, "Well, that's great, but what are you going to do for me lately?" And so the next picture here is what's still available for us just -- this doesn't even include fuel oil or everything -- anything. This is just continuing to take coal out of our market. We have another 34% reduction, which would be equivalent to removing all of the U.S. gasoline cars off the road today. That still remains out in front of us. And the powerful thing about that, both in the past and in the future, is that this is not subsidized. This doesn't require government subsidy. This has been done on the backs of good old fashion economics. And it's also allowed lower utility bills for consumers. And I think that's going to become a more and more important issue as the cost of renewables really starts to be exposed and borne within the utilities as the cost of renewables really start to show up in those markets. And so we still have so much to do in terms of reducing emissions here in the U.S. And if you think about, if somebody actually came forward today and said, "Hey, I've got a solution. It's not going to require any government subsidies, and it's the same as taking all of the passenger vehicles off the road today twice." People would say, "Oh, that's too good to be true." But the fact is it's right here, it's available to us, and there's nothing impractical about being able to accomplish it. It's not new resources that we don't control. And in fact, it's resources, and as you'll see later. We have plenty of resources here in the U.S. to be able to take care of that. So the opportunity, though, certainly doesn't stop at the U.S. border. In fact, the U.S. has been really the leader on this front. And so this is a picture from around the world. And a lot of -- one of the arguments, there's 2 primary objections that you hear from an informed -- considered to be an informed environmentalist that is really concerned about natural gases use in the market. The first thing is fugitive methane emissions. You're going to see -- hear from Micheal today what we've been able to do on that. But we can tackle that. That is not a challenging issue. Reducing fugitive methane emissions is not a challenge. The next thing though you always hear is, well it's going to be stranded investment because we're going to be off of gas in 10 years. And so it's going to be a stranded investment. Last year, we grew the amount of coal that we burn. We hit an all-time record last year in terms of the amount of coal. And China is continuing to grow that. They expect to continue to grow and increase their coal generation through '25. Oh, by the way, if you roll the clock back, about 5 years ago, that would have said that they were going to be done in '23. So I would just tell you, I don't think that, that's really all that practical, but that's going to start turning itself around. And the reason is, is because it's not economic. And so we're going -- the solutions that we can provide to the world as the U.S. are going to have to be economic. We can't afford to subsidize the whole world. And it's going to have to be economic and that's really where natural gas and U.S. natural gas comes in. So you're going to hear more about this from Chad in his presentation. But a really interesting figure that I came across in doing this research was that if we just took out the top 5% of the biggest carbon-emitting plants in the world. So just -- and there's a list of them, if we just converted those to natural gas, we would reduce carbon emissions from power generation, which is about half of emissions. We would reduce that by 30%. So think about what a powerful tool that is and come up with any other solution that's out there that you could actually go in and tackle power-generation emissions that quickly and again, on an economic basis. And so this is going to be a powerful tool. And it's -- I think it's going to be becoming very evident. You probably saw earlier this week or yesterday, the Germans came out and said they were going to start installing more gas-fired generation to keep up with their mix, and I think you're going to continue to see that around the world. So certainly, electrification is something that we all hear about, that video that you saw there. It's almost as electrification just automatically stamps out emissions and reduces and without thinking about where that generation and where that power is going to be created from. But as that's done, the U.S. is going to have to rely on natural gas infrastructure and particularly, storage capacity and pipeline capacity. And I've got some really interesting examples here that I'm going to walk through in a minute. But one of the things, I want you to keep in mind relative to Williams is that we sell capacity. And so that is a really important thing to know about what we have to sell. So there's one thing to look at annual natural gas demand. There's another thing to look at the actual capacity required to back up renewables. And you'll hear about storage facilities. We have storage facilities that will back us up for 4 hours. We don't have practical batteries that we can rely on for weeks at a time of -- because they have to be recharged. And so today, from a practical perspective, nobody is really willing to risk the reliability of the systems. And we'll talk about that here in a minute as well. So I'd ask the team to look at -- because we kept hearing about, "Well, we're going to electrify New York." And so we took a look at what it would take to electrify New York with solar, which is the most cost-effective tool there is right now, probably not in this region and certainly not today, as there are many days during the winter. But we -- and believe me, this is hypothetical, because this assumes that we would have sun shining on a peak day in New York and that it would be that we would have normal sunshine like annual average sunshine on a winter day. So not very likely. But so this is a very optimistic case, 0.5 million football fields of solar panels. By the way, that's everybody who always picks on Rhode Island. That's about 2/3 of the size of Rhode Island. And $1 trillion just in the solar arrays, just in the solar arrays. That doesn't include the transmission. It doesn't include the distribution. That's just the solar arrays that would take to do that. The distribution to be able to hit a peak load in New York City, you would have to more than triple today's capacity into these markets. And so it's just, people talk about, it's just not practical. And so in fact, it's not a very effective way of reducing emissions as we look at our options because, as we would do that, all we would be doing is taking out peak. So we would spend all this money to have this capacity just for a peak day. And so the actual emissions reduction would not be all that big. And so we really need to start looking at more practical ways of tackling these issues. But we also need to remember that from an affordability standpoint, even today in the Mid-Atlantic region on an MMBtu basis, to heat your home, gas is still -- this was in '22. So even with high gas prices we saw in '22, was still 1/4 of what it costs with electricity to heat a home. So even without those kind of large incremental build-out, natural gas is still going to be really hard to take out as a fuel. And you'll hear talk about bans and about -- everywhere, wants to talk about we're going to ban natural gas in our market. And if you read the fine print, on many of those, in fact, here in New York City, was kind of a classic because it said, "Well, we're not going to allow direct fired heat in a building that's more than 10 stories high." Nobody's put direct fired-natural gas heaters in a building that's 10 stories for a long time. The natural gas gets used to drive a chiller or to drive heating and steam down below in the auxiliary system, and that's distributed through the building. So direct-fired heating in a big building like that, nobody builds buildings like that anymore. So to ban that, it's certainly politically correct and it makes politicians feel good and popular, but it's really not an effective way. And it's -- and so far, it's really just been talk, not really anything that would impact. And so this is a picture now of, how a power grid regulator looks at it. So this is how ISOs look at it. They assign 100% to natural gas, solar and wind. It is varied depending on the time of the year, 30% to 70% on solar during the middle of the summer. And near nothing during the winter demand loads for solar. And wind is about 10% to 30% of the capacity. So when you install capacity in a market, that's the credit that the utility -- or sorry, the ISO is going to allow you to claim on that. And we're actually seeing utility commissions just start looking at this around the country. Utility commissions are starting to raise their reserve requirements, because it's too difficult to get people to agree to a lower factor, but yet they've determined that they really don't have the reserved capacity with the wind and solar. So the way they're fixing it is, they're actually raising the total reserve requirements into many of the markets today. And so that's an important issue as we think about natural gas and renewables and the need for that backup. And one other thing that I find really interesting, and we began studying this last year, is that the way the markets and the regulators look at this. As they add solar into a market or more wind into a market, on the increment, there's less and less capacity allowed. Because if you think about it in West Texas, let's say. If you add another wind turbine and you've already exceeded the times that, that wind turbine can hit demand because that's really the only time it's of any use is when it can actually hit demand. If you oversaturate an area like wind in West Texas or solar in Southern California, adding more solar really doesn't do anything because you've already exceeded on a pretty regular basis, you already exceeded the amount of demand. So the regulators are starting to get smart about that and they're starting to pull back and say, look, we're not going to give you any additional reserve capacity as you add more and more of that into the market. The bad news is our government subsidies with production tax credits, don't care. That's the reason you see power operating at negative power prices in West Texas, because we're getting the production tax credits, whether they need it or not. Another reason why, when the government subsidies come in, they tend to really confuse our markets. So this is an interesting picture in -- from Winter Storm Elliott. And just -- and this is, again, cold hard facts. This is right out of the EIA information. And you can see here that the orange there, we had wind operating at about 20 gigawatts at the beginning. That was right after midnight in Texas, and then that dropped down to 2 gigawatts by the next -- by midnight to -- end of that day. And you can see solar did its job. It came on during the period of time you would have expected it to, but the wind fell off and natural gas had to fill that in. Well, also at this time, natural gas was also getting hit really hard on reserve capacity. So things like our NorTex Storage that we have in markets, where there's a big pull on storage from both heating and now from power generation as it backs up these renewables is, we're going to become more and more valuable again. And I'd ask you to think about capacity, not the actual fuel consumed, but the capacity because that's what we sell, whether it's storage or transmission, that's what we're selling. This is another set of cold hard facts that's really interesting, I think. This is a look at both on our Transco System and Northwest System. You can see here the Northwest peak grew, over this time period, about 14% in 3 years. And the Transco peak, they grew about 9% over those 3 years. And so -- but look at the amount of wind and solar that was installed into the same markets here. And really, what this boils down to is, while the wind and solar will take fuel out, so the absolute amount of fuel that's going to get burned in a year, the capacity is going to continue to increase as we rely more on renewables. And we have more and more need for natural gas to back that up. So this is, I think, a really interesting picture. And you can run this in a lot of different ways. You can run it with cooling degree days and heating degree days, and you still will see the same thing that it's the normalized, that our loads, peak day loads are going up even on a normalized basis with the addition of renewables into our markets. So that's all, I think, a powerful story around the real pull that we're seeing for natural gas. But in addition to that, there's a real concern. And I can tell you, I've been working with a lot of the moderate Democratic senators working on permitting reform. And one of their primary concerns is they don't think we have enough gas. And so last year, when natural gas -- when Freeport went offline and natural gas prices fell, they said, "You see, that's clearly, it's just because we're exporting LNG is our problem because prices fell." And what you have to explain to them is, that wouldn't have happened at all if we had adequate infrastructure. Mountain Valley pipeline would have been online when it should have been. And if the market had been planning for that, we wouldn't have -- not have had that excursion because we have plenty of low-cost natural gas here in the U.S. What we don't have is plenty of infrastructure. And so this is a picture of the technically recoverable resources that remain in the U.S. today and up against the Wood Mac demand. So the Wood Mac is in the dark section there at the bottom and the remaining U.S. resources of about 3,000 trillion cubic feet. That's a big number of remaining resources. And this is even with a pretty strong growth in natural gas demand growth. Even with that, we would still have 53% of the remaining resources. And then if you study this stuff, you're going like, "Yes, well, whatever, but that's just technically recoverable resources. That's not proven resources," which you are right. And so if you look at this next slide, this is an amazing number to me. If you think about how long it takes for drilling to ramp up, from '20 to '21, our proven U.S. natural gas resources increased by 32%. And so our ability to take those technically recoverable resources and convert them into proven is really showing. I think, this year, and we certainly have good evidence behind this. But I think when the numbers come out this year, we're going to see that number grew again pretty substantially, because we were responding to price. If you think about it, into '21 and into '22, producers were responding to high prices. And so I think you're going to see even more proven resources come on the market out there. But the one thing that is a real Achilles heel to this whole story and our ability to take advantage of that is, that light blue bar over there where the Appalachia is 30% of our proven resources. And yet, we can't get pipelines built out of that area. And so if you think about really what it's taken to get that done and the kind of money that's been spent today, it's really disappointing in terms of how little we've been able to really take advantage of that great resource. Thank goodness, our REA project, Micheal is going to talk about that in a moment, but that's a huge accomplishment by the team to get REA permitted. And we're really excited about bringing that, and that will unlock some more. But if Mountain Valley pipeline doesn't get built, we've got a lot of interesting projects that we're going to be looking at that will expand along our existing right-of-way. And you'll see some of those today, but we've actually got some looking at basically refitting the pipe that we already have that goes South down today. And so Williams' right-of-ways today are one of the most powerful assets that we have that I think is extremely undervalued. So our ability to go in and pick up pipe and replace pipe along our right-of-way with higher pressure lines is a very simple way for us to increase capacity moving from the North to the South. And so we are exploring a lot of that. We've been counting on Mountain Valley pipeline getting built and that being a source of supply into our network. But if it does not get built, we've got a lot of really interesting projects that we've been working in terms of being able to expand our system in a way that is along our existing right-of-way and doesn't require the big EIA and the big permitting processes that typically would happen in terms of building a greenfield pipeline. So if MVP does get built, we've got a lot of great projects that are going to be getting picked up by that supply. And certainly, our gathering systems upstream of that, we'll enjoy that. But if it doesn't get built, we're going to have a lot of projects along the Transco system that I think you'll be impressed with. So it is amazing, though, if you think about it, we spent -- as an industry, there's been $11 billion now spent trying to build greenfield out of the Appalachia that have gone to rock. Now hopefully, MVP is a piece of that. Hopefully, MVP, that we won't be saying that in a year, but that's a tough bet to take given how many times the courts there have stymieing them on that. So -- but Williams really is the one that's positioned the best on this. And our Mountain Valley pipeline connection that you can see that would come into the middle of the system there in the Virginia, North Carolina area is where we would be able to serve a lot of those projects from. But if not, we would be building that up from the Northeast PA area and continuing to open up those resources to the South. But bottom line here is, we are extremely well positioned to be able to serve both the coal-fired generation markets that we talked about as well as getting the Appalachian Gas South to the LNG markets. And so now looking at Williams, we're now normally would have seen this, and we would say we handle 30% of the nation's natural gas. We're now up to 1/3 with the addition of MountainWest pipeline that we closed on last week and really excited about that. We serve 14 different basins. And as well, you've seen some move into the storage business on our part. That's not by accident. That's very much a strategy that we set out on several years ago because we think storage is going to become more and more important, as we have both LNG loads varying and we have electrification and renewable loads to back up. We think storage is going to become extremely valuable. So some of the moves we've made on that: One, buying NorTex; two, we were able to get market-based rates for our Washington storage, which is a very large storage facility in Louisiana on the Transco system. And so we've gotten the ability to put those at market base rates. That will be a really interesting upside for us in the future. And as well, Clay Basin storage, which MountainWest operate, is a critical piece of storage for the West. And so we think these are going to be high-value assets. And we are very much looking forward to proving that up. So what's our strategy gotten us? Well, the numbers here pretty well speak for themselves. And I'm not going to sit here and repeat these to you, but they are some very attractive numbers. The one thing, I would point out there is, on the 8.5% EBITDA, CAGR. That is above what we historically had said. We're targeting 5% to 7% growth with this business with about $2.5 billion to $3 billion of capital. We've been able to exceed that with a much lower amount of capital that we've been investing in the growth side. So we have been delivering on that. The dividend growth there has been coming along with that. And importantly, the coverage has built up, and John will show you a picture of that a little bit later. And of course, at the same time, we've been able to delever significantly and then a pretty extraordinary for a large-scale company to be growing our EPS at that 23% CAGR. So I looked at this and think, "Man, how many other companies are really pulling this off on all of their financials and really doing this?" And so I asked the team to kind of scale through the S&P 500 and determine really how we stood, given the track record of growth we've had and the attractive yield and free cash flow yield that we have in our business. And so I love this slide. This is, of course, scale and security on the bottom there, not to be surprised in the S&P 500. A lot of companies have both scale and investment grade. And then on the ESG side, you also would expect a lot of very responsible companies in the S&P 500. So a lot of folks in that group. But then the funnel gets pretty narrow here as we see a track record of growth going for only 10 companies in this group have been able to deliver 10 years of year-over-year EBITDA growth. And then we said, though, "That's all finding good, but it sure seems like that you're -- that yields would be -- for a company that's had a track record of growth like that, it seems like the yield would be quite a bit lower." And indeed, that's the case because we are the only one that is above a 5% yield that has that kind of track record and that kind of size and scale. So I love this slide. I think it really does point out how distinct Williams is, and what a great investment opportunity we are both historically, I think we've been undervalued. And I think as we sit here today, with all the growth you're going to hear about today, you'll see that as well. So just looking to Slide 22, this is just another cut at this real quickly. This is -- there's only -- we're the ninth highest dividend yield in the S&P 500. But again, only 1 of 62 companies in the S&P have been able to -- have 10 years of consecutive EBITDA growth across the business. And I think another thing that I think distinguishes on this is, we are now at 28 quarters of either meeting or exceeding consensus estimates on our EBITDA as well. So I think not just the growth, but it's been highly predictable growth as well. Looking to our achievements, I would just tell you, I get to stand up here and brag about the great efforts of the organization and the team I get to work with, but it really has been a spectacular year of seeing our strategy come together on one hand, along with a very crisp execution against that strategy and really delivered tremendous value. So if you roll the clock back several years ago, a lot of the things that people thought were our weaknesses actually showed up to be our strength in this year. And a really powerful set of upsides for us showed through this year. And really impressive if you think back of all the bumps and bruises for the last 10 years, the pandemic, very low gas prices, low NGL mark, all of those things, and we've been able to continue to keep that story of growth. But the team really has been executing according to our strategy extremely well, 3 great transition -- or sorry, transactions that Chad is going to talk about today and great effort on our wellhead-to-water strategy as well as being the first that I'm aware of anyway, of being able to sell next-gen gas at a margin to a U.S. utility and proving that up. So some really great efforts on the team's part there. On the growth side, I would just say, again, pretty phenomenal growth. But I think what's been underneath that is really important. We've had 11 new transmission projects that have added 4.1 Bcf a day on our system. So that's bigger than a Northwest pipeline just in those 11 projects. And our platform for growth looking forward is actually even brighter if you look at what we will see in 2025, when REA would be up full and running and the deepwater that Micheal is going to talk about today as well is up and running. '25 is going to be a big year for us as we see the efforts, all of those efforts come together as well. On the ESG front, I would just say, we've continued to deliver great scores on this. And I'm really -- mostly excited about really the employees that we have that are so in passion about doing things right. And really, our story has been to tell what we're doing because we've been doing a lot of these things right for a lot of years, and we finally started publishing what we were doing, and it's gotten us these pretty extraordinary rankings in -- amongst our peers, certainly, and even now on the Dow Jones Sustainability Worldwide Index as well. And so a lot of impressive accomplishment on this front. But again, it's not -- this isn't so much us doing anything different. It is just us doing a better job of communicating the way we run the business, which is always focused on doing it the right way. So why Williams? Well, many of you have heard me say it before, and probably more than you want to hear it, that natural gas really is the right here, right now solution. And Williams has both the right here and right now ability to take advantage of the growth projects that are out there and continue to drive a very bright future for us. Natural gas is not going to be able to be dismissed. It is not just a bridge fuel. It is going to be here for a long, long time, and it is going to deliver energy security, affordability and emissions reductions, all in the same package. The infrastructure that we have today and the capacity that we have on our systems are going to be absolutely critical to both backup renewables and to replace coal-fired generations in the market. And really, our footprint from our production areas to the markets that we serve is truly unmatched in the space. There's nobody -- and I'd be -- I think it would be hard-pressed to find any executive in the industry that wouldn't agree with that in terms of the positioning of our assets as it relates to this natural gas strategy. But the main thing I want to like to leave you with here is that, it's not just these great assets, it really has been the great team that I get to work with that has continued to deliver on the execution of this business day in and day out. And nobody in the group has been more kind of right in the wheelhouse of delivering on the execution of our projects and continuing to make our business more efficient than Micheal Dunn. And with that, I'm going to turn it over to Micheal Dunn. Thank you.

All right. Good morning. Thanks, Alan, and we were all drawing stars this morning to see who was going to give Alan's presentation, but I can assure you, none of us could have done it as well as Alan did. So it was great to have him up here and making it through that. This morning, I'm going to talk about several things here in regard to our operational strategy, give you some insight in how we approach the business from an operations standpoint and really talk about some of the great opportunities we see within our footprint that we've already accomplished and that we are going to accomplish here in the future, and then finally give you an update on our emissions reduction program that we have underway here at Williams. So we have 4 main pillars of operational strategy that we think about when we run the business here, and we establish our goals against these objectives. Our real ambition is to be the best operator in the space. And I think our team does a great job proving that out. And the opportunities that we have in front of us from a safety improvement standpoint, sustainable operations are really important to our business, and our team really takes that seriously. You heard Alan talk about some of the objectives that we've achieved there. The growth that Alan portrayed there in our business in the past has been very significant and tremendous, and we see those opportunities in front of us here in the future. And then finally, improving our balance sheet has been a really strong objective for this team, and we've done a great job improving that. And it really establishes us as a very resilient business going forward. We have an incredible safety culture here at Williams. Our team, every day works to improve the safety performance of our employees, our assets, protecting the public and our contractors. You can see a couple of the metrics that we track here, our Total Recordable Incident Rate was down 22% over the last several years. This is obviously a very important measure for us, protecting our employees and making sure that we're sending them home the same way they came to work every day. Loss of Primary Containment, is the graph you see in the middle there, and we've done a really good job improving that. And this is really a dual performance metric. This is not only a safety metric where we're keeping the products in our facilities, our pipelines, but it's also an environmental metric. And methane emissions are becoming much more sensitive to the NGOs and the other people that track our business. And it's something that we have complete control over in how we manage our methane emissions from our pipeline systems. And so lots of primary containment is another really important metric for our business. We have a lot of key performance indicators that we track in our business. LOPC is one of those. And it contributes to all of our employees' Annual Incentive Plans, including Alan, all the way down to our frontline employees. And we all have the same objectives when it comes to these ESG measures within the business. Reliability is a competitive advantage for Williams. We get a lot of business because of our history and our commitment to reliable operations. REA is a great example of that, where many of the customers on that pipeline system that we're going to build were coming to us and concerned about the reliability of the transmission providers providing them service and the fact that they couldn't depend upon that on peak days when they needed it. And that drove a lot of business our way in regard to Regional Energy Access. We see the same thing in our gathering and processing business. We are known as a very reliable operator. And we track metrics against this in every franchise that we have. And we've had nearly 100% of our capabilities of delivering our volumes that our customers have asked for on a daily basis. We've been doing that for a number of years now. Every one of our franchises have goals against that, and we track that every month to see how they're doing, and it certainly factors into their annual incentive as well as their performance measures in our management team. So a really important measure for us, and I can't reiterate how much business it does drive our way by being a responsible and reliable operator. A couple of years ago, we took a step back and we thought about how could we show more corporate responsibility and our commitment to sustainability. And one of the ways, we did that was by joining the ONE Future Coalition. This was an industry-led organization that really came together and determined what can we do from our commitment to methane emissions reductions. And you can see the graphs here. We've done a tremendous job in our organization reducing our methane emissions, and we're well below the 2025 targets that were established by ONE Future. And I'm very proud of that. But one of the other areas that Chad will talk about in his presentation is our now, a new commitment to the oil and gas methane partnership. And that's another commitment where we can show our corporate responsibility, our efforts to improve our sustainability as a business and make a new and additional commitment to methane emissions reduction. You see some of the metrics on this chart that we track from an environmental stewardship standpoint. We've done a tremendous job reducing our notices of noncompliance. Our reportable spills are down significantly. And we said last year, for the first time, an emissions reduction goal for methane within the business. We had a 5% target on that. We blew way past that. Our team did a tremendous job reducing our methane emissions last year. Like I said, this is one area that we have a lot of control on. It's how we go out and approach our business when it comes to maintenance and construction. And instead of just going out and opening up the valves and releasing the natural gas in the pipelines as historically been done. We do a lot of recompression on our pipelines, where we have either dual pipelines or the capability to move it into another pipeline. And that takes a lot more cost, and it takes more time to build your projects that way. You get to plan better, but we're doing that and making remarkable reductions in our methane emissions in the organization. You heard Alan talk about our first delivery of next-gen gas, and we did that in conjunction with Coterra and Dominion on both ends of our gathering and transmission systems and very pleased to have that first delivery of next-gen gas under our belt. Another area that we feel incredibly committed to is stakeholder engagement. And this means having great relationships with our landowners and our regulators that we go out and seek permits from. And you might ask, "Why is this important? Why is this important to an investor?" Well, it makes a difference when it comes to getting permits for projects, when it comes to shaping policy at the FERC, when it comes to agreeing with landowners about your easements. And I have a great example. In Regional Energy Access, we have 337 landowners along that 36 miles of pipeline loop and the meter stations that we needed to build this project. And that was 477 tracks of land that those landlords owned. We received agreements with every landowner prior to actually needing a condemnation authority to be established there. And we were able to go to the FERC and tell them we have all land owners signed up, and that's really important at FERC right now. They are taking a much more measured approach to landowner concerns about how pipelines are being built and designed on landowners' property. And they are giving a lot of credence to landowner concerns. And when you can go and show FERC that you have all of your agreements in place, long before you really even need or even have your condemnation authority. And if you understand the Natural Gas Act, we don't have condemnation authority until we get a certificate from the FERC. And we virtually had all these landowners signed up even before we had that certificate in hand. So a great job by our team, and it does pay dividends in the long run for us to be able to continue to grow our business. So when we start thinking about growth in Williams, it really starts with a great asset position that we have. We have a vast asset position in the gathering and processing in the transmission business. It creates a significant number of opportunities for us. And I can tell you, having the Sequent organization, a part of Williams has even leapfrogged that much more than we expected when we acquired Sequent. There's a lot of examples where they've brought market intelligence to us well ahead of where we had been receiving that in the past. Because they are talking and they have their fingers in virtually every pipeline system in this country and some even in Canada with the old transportation capacity. So they know what's going on out there and to a great extent, well beyond where Williams' intelligence was. And it's been great having them in-house, and I'll talk about some of the examples where they've really helped us jump-start some business. So I tell, this is my opportunities on a page. And this really shows the breadth of geography we have in our business and the opportunities across our entire asset base. I'll go through a lot of these in more detail in the coming slides, but this is a great snapshot of the opportunities within the Williams' asset footprint. For us, growth really starts with incredible project execution. Our teams have been knocking it out of the park for a number of years. And we used this example up here, $145 million under budget with these last several transmission projects we put in on the Transco system 22 months ahead of schedule. So we bring the revenue in early. And the bulk of these were negotiated rate contracts. And if you understand how that works, we take the risk of either overruns or underruns. So we take schedule risk. We take permitting risk. And for that, we typically get higher returns on those negotiated rates. And when we can bring the projects in under budget, we get even higher returns. And so really doing well here from a project execution standpoint. And I couldn't be more proud of our team and their accomplishments here. Another area that we track very closely is the efficiency of our business by using the operating margin ratio. And this is really how much of our revenue gets to the bottom line. We track this in each one of our franchises across the entire business. And you might think, "Gosh, it's an inflationary environment. How much has it impacted Williams?" We have a lot of protection in place in regard to inflation. We have escalators in more than 75% of our gathering and processing agreements. So when the CPI or whatever indices we're using, increases, we're able to incorporate that into our rates every year. So we're well protected there going into 2023. We certainly saw that protection kick in, in 2022. We have the same opportunity on the transmission side of the business. A bit more difficult. We have to go through the rate case process there. And certainly, we have some headwinds in regard to how long it's been since we've had a rate case, for example, on Transco. We put our last rate case in service in 2019. We have an obligation to come back in 2024 to file another rate case in August. And so the base period for that rate case will start this summer. And as you can see here, a little bit flat on our operating margin ratio. And certainly, we've been able to overcome the inflationary environment we've seen over the last year or so. But really ramping into that Transco rate case, we're well prepared to go in and justify higher rates if need be to cover any inflationary measures that we've seen on the Transco system. Our team has done a really good job controlling costs. In a lot of our operating areas, our costs are below 2018 levels, where we've taken a lot of efficiency and using our scale to actually improve our efficiencies fairly significantly in the field. So let's go through some opportunities here. I've listed all of our franchises here on the right. I won't spend a lot of time on here. But it has some background information, you can see all of the gathering and processing franchises we have as well as our TGM, Transmission Gulf of Mexico asset base. So let's start with TGM. And when we start with TGM, we talk about Transco. Transco has been an incredible growth engine for the Williams Companies. You heard Alan talk about the 11 projects that we put in service with 4 Bcf of capacity increase. The bulk of those have been on the Transco asset base. You can see the growth we've had here. We expect that to continue. We've got some opportunities here that I'll talk about on REA. You see, we're flat going into 2023 with a capacity position here. We have a real opportunity to accelerate the REA project, which I'll talk about in a moment. But by the end of 2025, we expect Transco to be a 21 Bcf a day pipeline system. To put that into perspective, that's about 20% of all the demand on an average day in the United States on one pipeline system. So Transco, I've said this before, I'll say it again. It's the largest and the fastest-growing transmission pipeline in the country and expect that to continue for a long time with the opportunities we see. A little bit about our backlog here. We have about 8 Bcf -- sorry, $8 billion worth of opportunity in our backlog, which comprises about 10 Bcf of capacity on the pipeline systems. We've moved 8 projects comprising about 2 Bcf a day into execution over the last several years, primarily on the Transco business. Our teams work this backlog very hard. We're in active conversations on all these projects that you see here on the 25 projects, and we're going to be rolling out more opportunities as the coming weeks and months come on. We're really close on many of these exciting opportunities. I wish I could talk about more of those today, but more to come on that. In the next several months, you'll see some more information coming out from our organization and just really excited about the opportunities we're seeing. The Mid-Atlantic on Transco is going to be a tremendous growth engine for us. And if you think about what occurred there during Winter Storm Elliott, the utilities were really surprised about the demand that occurred on the natural gas utility basis there and the electric generation that was required. They had a pretty significant margin of error there. It was about 10% miss on the electricity demand based on the actual temperatures and wind that they saw. That is a significant miss when you're thinking about planning for your peak days. And I think that's going to have some of the utilities there rethinking their peak day scenarios and, as you heard Alan talk about, what they're thinking about from their capacity margins that they have to have out there and ready to go and available. So that's going to really bode well for us establishing new capacity into that region. And then the LNG footprint in the Gulf Coast is going to be another growth engine for us on the Transco system. So really interesting development that I'll talk about first on this slide. The bottom 2 projects you see there are Southeast Energy Connector in our Texas to Louisiana Energy pathway. I tried to say that real fast. FERC just recently came out and changed their environmental review process on those two projects. And if you recall, there was a policy statement that came out last year from the FERC, virtually required every project to go through an environmental impact statement that was filed at FERC. A lot of that was pulled back, but really the stone had been set in regard to how many of these projects were going through an EIS. And for us, that's more time. That's more money out the door. And some of these projects are fairly simple projects, like the bottom two. It's really a compression-only and some retesting of some of our systems there. And FERC just recently came out last month and changed those 2 projects from an EIS to an environmental assessment. I think, "Okay, what does that mean?" It's about 5 to 6 months shorter process time for getting our permits, and we're able to accelerate those projects. But really, what it means for the industry is, it's a bit of a turn of positioning from FERC as a new Chairman has come in. Chairman Phillips is an interim Chairman right now. But he is changing the way the FERC is evaluating projects. And I think that bodes really well for the industry. It certainly provides us a lot more confidence about us putting our projects in front of the FERC. We have 7 there right now or soon to be 7 with the 2 new ones that you see here on the list. And so I'm highly confident in our team's ability to execute projects. And I'm even much more confident now about the ability for us to receive permits from the FERC with where I've seen a little bit of a change in posture from the FERC. So very optimistic about those changes. I'll talk more about REA here in a moment, but our 2 new projects, our Carolina Market Link and the Alabama Georgia Connector, these are projects serving residential, commercial and power generation in the Mid-Atlantic and Southeast. And as I said, there are huge opportunities for the Transco organization. And I am incredibly excited about the opportunities that we're looking at in our backlog today. All right. Great news on REA. We received our FERC certificate in January. We would have liked to have it sooner, but the EIS was finished last summer, took about 5 months to get a final certificate from the FERC. It's a very clean certificate. We immediately accepted that, filed our implementation plan a few days later, gone through the rehearing process. That's a 30-day process from when the FERC issues a certificate. Really, no surprises came in from the rehearing request that were submitted to FERC, nothing that hadn't been already addressed in the EIS or in the certificate order from the FERC. And so right now, we're sitting here with all of our permits in hand. We received our last Corp of Engineers, water permit in the first week of February and our Pennsylvania permits. We received our New Jersey air permits last year and a really interesting story there. We went in with the idea of what can we do to help pave the way to permit our new compression that we need to install in New Jersey? And New Jersey is a tough area to permit, but the regulations are pretty cut and dry on the air side. And so we have the opportunity to build at some brownfield sites, removed some of the existing 1950s vintage compression, take that out of service under our emissions reduction program. And at the same time, install new horsepower to replace that and new horsepower for REA at the exact same time. So that's the proposal we made. Significant reductions in our methane emissions through that effort as well as our NOx emissions and very well received by the state of New Jersey in our permitting process. So really great job by the team all across the board in designing this project in such a fashion that it could be easily permitted. And it's no easy feat to permit any projects these days, but I feel very confident about the way this was designed with no water permits needed in New Jersey, where we've had trouble in the past. We have a greenfield electric-driven compression in New Jersey, virtually no permits needed for that. And then our New Jersey air permitting and our water permits in Pennsylvania. Pennsylvania is a tough state to build in, if you don't do it right. But we have a great reputation in that state and no issues at all getting our permits there. So all permits are in hand. All landowner agreements are signed and executed, and we have submitted our notice to proceed request from the FERC. The acceleration opportunity we have is if we can establish our tree-clearing window and get all of our trees down by the end of March, then we can start pipeline construction this year. And that window is very tight. It's November to the end of March. That's when you can clear trees, primarily for bat species that roost at those time of years, you have to stay out of. And so we've made that request to the FERC. And if we can get our pipeline loops installed, we believe we can have at least half of this capacity online before next winter. And that's the acceleration opportunity here. The compression takes about 10 to 12 months, so we may miss the winter for the compression, but it certainly has an acceleration opportunity. Assuming that we can hit this tree clearing window even for our compression, that should be online midyear next year. So really great news in regard to the REA front. There was a lot of concern from a lot of people that didn't think we would be able to permit this project and didn't really give us a lot of credit for being able to do that. And I just want you all to know, we have a lot of confidence in our ability to do this. And we will absolutely find ways to design these projects that we know we can permit them going forward. So an update on our emissions reduction program. This is something that we've spoken about in the past. We have about $1.3 billion projected for this program. This is primarily on the Transco and the Northwest pipeline systems. We have underway a number of replacements already on both of those FERC transmission pipeline systems. We have about 184 compression units that we'll be replacing between now and 2030. And that's a vast undertaking. It's really a great opportunity for us to reduce methane emissions as well as NOx emissions. And as you likely know, NOx emissions are a precursor to ozone. And ozone is a human-health hazard. It's very problematic for people with asthma and other health conditions. And it's very important for us to continue to find ways to produce NOx. And we've done that significantly on the Transco system. We've had about a 90% reduction in NOx from the original installation of those units, with all the retrofits we've done over the last several decades. And we can't do any more of that. Those units are as controlled as they can be, and now it's time to replace them. And that's what this program is all about. And it creates a great investment opportunity for us on our regulated businesses and where we can go in. We talked about maintenance capital. We have a lot of maintenance capital in our business, but the bulk of this is on our transmission systems, where we ultimately get a FERC-regulated rate of return from those investments. And the really interesting thing about our Northwest Pipeline system, we had a rate case that we filed last year. We pre-settled our rate case that we were obligated to come back for. And within that settlement, we received an emissions reduction program tracker and one of the first in the industry for compression replacement. And it was important for us to be able to do that. And why that's important is because as soon as we put those compression replacement projects in service, we're able to raise our rates. And that was through agreement with our customers as well as the FERC. And we're going to attempt to do the exact same thing in our rate case on the Transco system. And as you know, we tried to do that last time. It's much more difficult negotiation process on Transco. We have a large number of customers, and we also have utility commissions that participate in those negotiations. So it is a much tougher environment on the Transco negotiation front. But we're optimistic that we can prove out why this makes sense for the environment as well as for our customers to have some certainty about what those rate increases would look like as we put this emissions reduction program in place. So really a great opportunity for us to continue to invest in our regulated assets and very pleased with how the performance of that is going so far with our team. Moving on to the deepwater Gulf of Mexico. We have 6 major projects underway in the Gulf of Mexico right now with various customers out there. I'll talk about Whale in a moment. But in the Central Gulf of Mexico on our Discovery system, we have the Shenandoah project, Anchor and Salamanca. Shenandoah is the only one that requires capital investment on our part, and we're about 35% spent on that project already. And on the Eastern Gulf of Mexico, we've got the Taggart project and Ballymore. Taggart is going in service in a few weeks. That's a tieback to our existing facilities. No capital investment required. And then Ballymore is the opportunity that was announced last week with Chevron. This is acreage that was dedicated to us in the Gulf of Mexico. We buttoned up all of the agreements with Chevron and announced that last week and really pleased to see that they are actively pursuing the opportunity here and very fortunate to have a great customer like Chevron working with us on that project. The Whale project, we reached a significant milestone on the Whale project this fall. We installed all of the offshore pipeline on the Whale project. It was about 150 miles of 18-inch pipeline that was installed by the ship you see here. This is the Allseas Solitaire vessel, one of the largest offshore pipelay vessels in the world. And that's our platform you see there, which is actually a fairly significantly large platform. This ship's over a 1,000 feet long. And it's a marvel of technology. They did a tremendous job, very safely putting in this pipe in water that was about 400 feet deep right here at this platform, extending out to the Southern reaches of our opportunity there in 8,400 feet of water. Just a marvel of technology that has been -- made us the opportunity to go out and install pipeline in that water depth. All of the underwater facilities are installed, and now we're just waiting on the producers to come in and install their facilities and their floating production systems. We derisk the project significantly in negotiations with the customers, having this out and done early. They wanted us in there and to be finished to make sure that we've got. The facility is ready to go a couple of years ahead of time. So now we've got modifications to the platform you see there. That will be installed this year and then some onshore modifications at our Markham facility to handle the rich gas that's coming ashore. We expect the capital to be less than $450 million here and we're about 65% spent on this project already. So very much derisked by getting this offshore pipeline work out of the way there. And I can't say enough about the team's efforts here in getting this project closer and closer to reality. So I wanted to provide an update on the NorTex acquisition that we made. And you'll hear more from Chad on this in the presentation from him today, but a really great opportunity for us to expand our footprint in Texas. This is in close proximity to our Barnett Shale gathering systems in Texas. And this was a great example of us seeing an opportunity with our Sequent organization helping us out. They have storage in a lot of facilities across the country. And so they see what's going on with storage. The demand for storage is just increasing. Every time a contract comes up for renewal, those rates are increasing and increasing fairly dramatically. And actually, the terms are lengthening out. Typically, storage facilities 2, 3 years might be the longest you get a contract. You're seeing some contracts going out 10 years now. A lot of that's driven by the LNG players going in, and they know they need storage. They need to have access to storage. Whenever there's upsets on their system, they need to move gas into storage or out. They're actually going out and contracting for these longer terms. And so it's forcing everybody to go out and term up for longer contracts and driving up breaks. And that's exactly what we saw in the opportunity with NorTex. We're already seeing that when we're recontracting. You have those conversations, those rates are going up, and that's exactly what we projected here. They've also got a transmission pipeline that they were in development on. It's 11 miles, a 24-inch Wolf Hollow pipeline. That would be coming online this summer, and it's the sort of power generation in the Dallas-Fort Worth market. But really a great story for us, integrated really quickly into the business, about 26 employees that came over from there. And they've already set a new peak day during Winter Storm Elliott. That's a peak day that it stood for 6 years prior to our acquisition, and really pleased to see the performance of this asset so far. So another great story for us is the opportunity to expand our footprint when it comes to FERC-regulated fee-based transmission business in the MountainWest acquisition. We closed that last week. It was announced in December. And once again, another opportunity we saw to increase our scale on the FERC-regulated transmission side. It overlays very nicely with our systems as you can see here. Chad will talk more about this. But we're really interconnected here with our Wamsutter upstream acreage that Sequent is now marketing all of the gas coming off that. And if you recall what happened this winter, if you saw the pricing differentials across the Rocky, CIG pricing was very low. Pricing at the Opal hub was very high. I mean, we saw $30 differentials across Wyoming this summer, and that was going right through these assets. And certainly, we benefited from that in the marketing of our natural gas coming off the Wamsutter partnership with Crowheart. Even today, there's a $3 differential across Wyoming with prices where they are at the Henry Hub. So we love these assets. We love FERC-regulated transmission businesses, and it's right in our wheelhouse for us to find opportunities to continue to grow these businesses, take advantage of our scale, bring a lot of better pricing power to this team's efforts in regard to replacing assets and growing their business and just beginning the integration work today with that team. But I know that team well. We met with them last week. And really pleased to have a great group of employees and professionals on board with Williams now. And they look to be a very energized workforce with some of the transition things that they've gone through the last several years. They've got a home here at Williams and we're happy to have them on board with us. So let's jump into the Northeast, talk a little bit about what's been going on there. We've seen a lot of volume growth in the Northeast for a number of years. And we've taken advantage of our scale there. The Marcellus and Utica, we're one of the largest gatherers in the area, especially in Northeast PA. And we see a lot of opportunity in Northeast PA. Just as a reminder, Regional Energy Access starts right at our assets. Our gathering assets are the interconnect, and it's going to unlock a lot of takeaway capacity right out of our Bradford and Susquehanna Counties. And if you think about the build-out that we've done up there in Bradford and Susquehanna, a lot of that backbone infrastructure is complete. A lot of our capital going forward is compression and well connects and not a lot of backbone required because it's already built out. And this unlocks 800,000 dekatherms per day that will be coming right off our gathering systems. And REA will be unlocking even more potential out of our gathering system. So once again, a great story about the synergies across our business and sequence right in the middle of that being a capacity holder on REA. We've been able to continue to grow our gross margins here and our EBITDA in the Northeast chasing a lot of the rich gas opportunities. And if you think about the rich gas for us, we get to gather that gas, we get to process it, we get to fractionate it and even some of the NGLs, we transport the ethane off to other third-party pipeline systems. So we touch a lot of the molecules multiple times in that rich gas play. And a lot of continuing opportunity we see there, and the dry gas has been growing significantly as well. And so we started unlocking more and more of this takeaway capacity. We're going to continue to see opportunities coming out of the Northeast. With our scale, we've been driving the dollars per Mcf up as well and tremendous story here and our team being more efficient and also the capabilities that we have in the rich gas play. And that continues to drive our margins higher here, and we're taking advantage of the efficiencies that our team has been able to incorporate with the JVs that we brought together in the Northeast, and we continue to find opportunities just like this. But a really good story here, and I expect this to continue as we see more opportunities in the rich play. Another great story in the Northeast is the excess cash flow that's generated from these assets, $1.5 billion in 2022, and I would expect this to continue to accelerate, as we have lower and lower capital investment requirements because of that backbone infrastructure that we have there. And so just a great story here. As you can see, scaled down that capital need there quite a bit, but still increasing the EBITDA coming off these assets tremendously. The expansion opportunities we have in the Northeast right now, we have the Susquehanna gathering expansion underway for Coterra. This is what we have called the [ Olympus ] program, going online later this year. It's about 300,000 dekatherms of new gathering capacity for them. The 2 expansions we have in the Utica and the Southwest Appalachia, those are on the rich plays. Utica in the Cardinal systems for Encino, a private upstream, very active producer up there that we have a great number of opportunities with. And also the Flint area, that's our dry expansion opportunities. We're talking to them about as well and continue to see opportunities there, assuming that we find ways to unlock capacity out of the area. And Southwest Appalachia is another important customer. They're about 100 million a day coming online in the second quarter of '23. And then finally, the Blue Racer interconnect. Another great efficiency story here by our team, where we found an opportunity that we were seeing a lot of growth between the Cardinal and the Southwest Marcellus. That was really taxing the capacity of our outgrow systems in West Virginia. And instead of building a new turbo expander plant, significant capital investment there, we've built a 1-mile pipeline over to the Blue Racer system. And we were able then to redirect volumes into their system that we own 50% of with First Reserve as well as our UE OEM assets in Ohio. So we have the opportunity to divert volumes over there and take advantage of latent capacity as it becomes available on their systems and as our systems on the West Virginia side are full. And we can make that play back and forth for a number of years here I think. And really take advantage of all of the capacity that we own and participate in with our JVs there in the Southwest Appalachia area. So a great story there. It increases our EBITDA per Mcf opportunities and just really a great capital efficiency story. All right. Let's move to the West. 9,300 miles of gathering that we have in the West, about 5.5 Bcf of volume going through these systems last year, really significant growth that we saw primarily from the Haynesville, but some of the other areas as well. The Barnett picked up last year with pricing. We actually saw growth in the Barnett last year, which was a great story. And if you recall, we have those commodity-based contracts in the Barnett, was a huge growth driver for us last year, but we also saw volumes grow there as well from our customers in the Barnett. Another great story here. Excess cash flow generation in the West was about $750 million. We did have an uptick in capital last year, and a lot of that was driven by our LEG project, large diameter gathering system we're building out of the Haynesville, as well as our Haynesville expansions where we spent the bulk of that CapEx last year. And another incredible growth story here. Almost 50% improvement in our legacy Williams assets on a year-over-year basis in volume. And with the Trace acquisition, we tripled our volumes coming out of the Haynesville and our gathering systems. So really, we like the Haynesville. This is a very prolific play. And a lot of constraints are starting to show up on takeaway capacity. That's why you see some of the producers talking about dropping rigs. We're seeing capacity. We're seeing basis differential widen out a little bit. And this is another story where Sequent really helped us out here. Sequent saw that coming. They were able to go out and take some short-term contracts out on pipelines out of the area. And we're able to lock up that capacity before the LEG project comes online and really helped us, obviously, with our GeoSouthern partnership on the upstream there, being able to move our capacity that Sequent markets all of -- 100% of that. But also Sequent markets a lot of gas for our gathering customers out there. And so they were able to get out there in front of that, make sure that we can keep that volume flowing before those constraints really impact us and just another great Sequent market intelligence story that we took advantage of. So around the horn here, we've got 3 projects that are underway in a substantial basis, almost complete in the South Mansfield, the Mansfield and the Springridge. These are very efficient economical expansions, primarily treating and compression projects for the most part. And the bulk of that capital, about 95% of that was already spent in '22. So bringing those on later this year in tranches as we go through the year. The Haynesville West is over on the other side of the border in East Texas. That one is just getting started. So we're about 5% spend on that one. So the bulk of the expansion here will be coming online on the legacy Williams side in Louisiana. And by year-end 2024, we'll have 5.5 billion cubic feet of capacity just in the Haynesville and perfect timing for the LEG project to come online in the latter half of 2024. And just a real quick update on LEG. We were able to file our permits earlier this year, expect to go through that permitting process. And in the fall, we'll have our permits in hand. Shortly thereafter, we'll begin construction. I should back up one moment here. I forgot one of the most important things on this slide. We just recently had our announcement in regard to Chevron. With a new 26,000-acre dedication with Chevron, really great commercial opportunity for us, working once again with a great customer in Chevron. They were looking for a company like Williams. It's a very reliable operator, and they know us well. And we've not only got a significant dedication from them in their East Texas play, but a commitment on the LEG project from them as well. So I'm very pleased to have them on board with that and certainly was remiss in not talking about that, one of the most important things on that slide. All right. Wrapping up here, our emissions reduction progress. We've talked about this in the past. We've increased our transmission capacity on Williams by about twofold over the last -- since 2005. Our gathering capacity is up 450% in that same time frame. And we've reduced our emissions on an absolute basis by 47%. And over that same period of time, our team has done a tremendous job growing the business, while, at the same time, reducing our emissions footprint. Even more importantly, we're starting to watch our methane intensity on our emissions profile. So we started looking at that, a 39% reduction in our methane intensity since 2018. And that's important for a number of reasons. I've said, we have a lot of control over our methane emissions, whether it be valve operators who we replace, whether it be our construction practices and our maintenance procedures that we go through. So we go out and reevaluate all of our operating procedures and we control that methane emissions profile. The other reason is, it is because you probably all know this, but methane is much more potent on a short-term basis from a greenhouse gas issue. And you can look at that in a number of different ways. But where we can control these emissions, we're going to do that on the methane side, and we're going to do everything we can to continue to find ways to reduce that methane emissions footprint. Then finally, our commitment that we made for a 56% reduction in absolute emissions by 2030. We talked about this a number of years ago. We're at about a 47% reduction, as I said on the previous slide here. And we've got a lot of opportunity to continue to ratchet this down. Our operations practices, certainly something that we can do, as I talked about on the methane side, but our New Energy Ventures group has a lot of opportunity here as well. The number of solar projects that we're installing this year, which will go out and will provide power for our own facilities on our own footprint, on our own land. And we'll have those in place that will certainly help in regard to our emissions profile being reduced. And another great opportunity that is coming out of our New Energy Ventures group. You'll hear more from that on Chad later in the presentation. So in summary, a heck of a lot of opportunities here in front of us from Williams' standpoint. We're really pleased about the growth that we've seen in the past. You'll hear about that from John here in a moment about how '22 went. And the opportunities we see in front of us in 2023 and beyond are incredibly vast and really excited about the opportunities we have in front of us. So looking forward to your questions here in the Q&A, and I'll turn the time over to John now.

All right. Thank you, Micheal. Good morning, and welcome. Williams really is a unique investment opportunity, and it's great to be with you this morning to talk about Williams' excellent financial strength and our growth outlook. So in my presentation, we'll be covering 4 main areas. First, we're going to review the financial performance for 2022, which was another consecutive record year for the company; and we'll also look at 2022 in the context really of the long history of growth that we've had with the company through all different types of commodity price scenarios. Second, I'll lay out our expectations for continued growth in 2023. Third, we'll revisit our capital allocation strategy. And fourth, we're going to look more closely at the road map to really the exceptional growth we see coming in late '24 and into '25 from contracted in-flight projects. But before we dive into the details on 2022, let's take a quick look at the longer trend of financial performance for the company. 2022 really was an exceptional year for the company. We saw a 14% adjusted EBITDA growth off of 2021. And importantly, 2021 was also a record year with 10% increase over 2020. We've produced an 8.5% CAGR with growth in all 5 years, including the very challenging year in 2020. Our EPS has seen a 23% CAGR with steady growth across all 5 years. Our AFFO per share dividend coverage has averaged 2.1x over this 5-year period, that strong coverage on a dividend that grew at a 6% CAGR over this 5-year period, which is right in the middle of our long-term cash flow growth target of 5% to 7% for our base business. And then finally, you see the tremendous improvement we've made to our balance sheet strength over these 5 years with a 26% improvement in our key leverage metric, really a testament to pursuing the operational leverage in the business and the disciplined capital investment we've made over these years. All right. Let's talk about '22. So let's take a closer look at how the record '22 year-end ended in the fourth quarter. The fourth quarter of '22 was a really strong finish to a strong year with record quarterly EBITDA of over $1.7 billion. That was up 20% over the record fourth quarter that we had in 2021. Now looking at the chart, and starting on the left-hand side, it was another great quarter for the upstream operations, up $62 million, driven by the growth we saw in the Haynesville area as we've really proved up that acreage, which didn't have much production at all just a year ago. Our Wamsutter upstream operations have been pretty severely impacted by some really difficult weather that we've seen in Wyoming this year. Shifting now to the core business performance and starting with the transmission in Gulf of Mexico business, which was up about $15 million on higher Transco revenues and also a full quarter of the NorTex acquisition, which closed on August 31. Moving now to the Northeast. Up just $5 million were higher revenues at the Ohio Valley Midstream JV and the Cardinal areas were largely offset by lower cost of service rates in the Bradford area. And we also did have some weather-impacted volumes across multiple locations in the Northeast as well. Moving to the West, which was up $67 million year-over-year, with the Trace acquisition making up about $25 million of that $67 million increase. Overall, we saw higher Haynesville volumes, including the Trace acquisition and higher gathering and processing rates, including some related hedge gains. These improvements were partially offset by the difficult weather again that we've seen out in Wyoming and Colorado. Finally, our gas and NGL marketing business had an excellent fourth quarter with EBITDA of almost $150 million, up $138 million over last year. And really, this was led by weather-related volatility that provided strong profits across our marketing transportation positions. Now this business actually absorbed a $77 million inventory revaluation hit on their year-end natural gas storage positions that will actually ultimately position the marketing business for a very strong 2023. So it was a strong finish to a strong year in 2022, with record EBITDA of over $1.7 billion. Let's shift now to take a closer look at that full year comparison. Now for the full year, we saw a record annual EBITDA of over $6.4 billion, a $783 million improvement or 14%, really driven by broad-based growth across all of our businesses. '22 ends up exceeding the high end of our adjusted EBITDA range even after we raised it twice during last year. Starting now with the left-hand side of the graph, you see 2021's [ $5.635 ] billion of EBITDA in gray, and then you see the unfavorable absence of the 2021 $77 million Winter Storm Uri impact. Moving to the $245 million contribution we had from our upstream operations last year, which were really Wamsutter related in the first quarter of 2022, but then driven by the tremendous Haynesville growth that we've seen through the remainder of the year. Shifting now to the core business performance. The transmission in Gulf of Mexico business saw about 4% growth last year, driven by higher Transco revenues, including the Leidy South expansion project as well as the NorTex acquisition. The Northeast business saw a 5% growth, driven by higher revenues under Ohio Valley Midstream JV, the Laurel Mountain franchise as well as the Cardinal area, partially offset by those lower cost of service rates in the Bradford area. The West saw a $255 million or 27% increase, driven by higher gathering and processing rates, but also a strong volume growth in the Haynesville, including the Trace acquisition. Finally, our gas and NGL Marketing segment produced $258 million of EBITDA, up $170 million, driven by favorable margins in a year with very high natural gas price volatility. And as Chad will discuss, it's really volatility and not absolute natural gas price that's driving the profits in our gas marketing business. So again, $783 million increase in EBITDA last year on broad-based growth across all of our businesses, generating a 14% growth over the prior year in 2021. So let's take a closer look at the overall EBITDA profile for 2022. And this chart really illustrates the diversified sources of 2022 EBITDA, starting in blue, with the 43% contribution from our Transmission and Gulf of Mexico businesses that are anchored by our FERC-regulated pipelines: Transco, Northwest Pipeline and Gulfstream. And of course, next year, we'll add the MountainWest pipeline to this group as well. Next, we have a 38% contribution in green from a diversified set of low-cost gas-directed supply areas, including our large Marcellus and Utica systems, but with strong growth last year from the Haynesville as well. The oil-directed supply areas in purple amount to about 8%. And then you see the 6% contribution from our E&P joint ventures last year and about a 4% contribution from our gas and NGL marketing services, even after that really outstanding year that they had. So again, the diversification of our cash flows has been a great source of stability and growth for our business. And although the higher commodity prices that we saw in 2022 did provide some tailwinds for the business, especially for that 6% upstream contribution, our natural gas-focused business has really been able to produce steady growth throughout various commodity cycles. And that's what we've shown here with a longer look back at our base business EBITDA growth, excluding upstream -- the upstream joint ventures in any businesses that we divested over this period. Now there's been a lot of focus on the falling natural gas prices lately. However, what you can see in this graph is that we've really built a business that is primarily levered to the growth of natural gas volumes and reserved pipeline capacity. And as a result, we've been able to steadily grow our EBITDA with lower natural gas prices. We've been able to grow our base business EBITDA for about a 6% CAGR from 2015 through 2022, where the average Henry Hub price was only $3.27. And in 6 of these 8 years, it was $3.07 or lower. But 2022 definitely did show what our business can do when natural gas price spikes and becomes more volatile because, as I just said, it's really volatility that is the driver of our marketing profits versus just pure price. Okay. So having covered the longer trend of our strong financial performance for the company, we're going to turn our attention now to the future with a review of our 2023 financial guidance. We'll do a pretty quick review of the metrics on this slide. And then we'll have more to say about the EBITDA drivers and the CapEx drivers on the next couple of slides. We have an adjusted EBITDA range of $6.4 billion to $6.8 billion, with the midpoint at $6.6 billion. That's 3% growth off of 2022. We've also provided the separate upstream EBITDA guidance with a range of $230 million to $430 million. Now the upstream business EBITDA is definitely where we see our most direct commodity price sensitivity at this point. And I'll provide some more information on that in a moment. We have an EPS midpoint of $1.80 per share, fairly flat to 2022 due to higher noncash depreciation expense and forecasted interest expense. Our AFFO per share midpoint is $4.02. And based on $1.79 per share dividend, that's 2.25x coverage. So again, we're continuing strong dividend coverage in 2023. Leverage is planned at 3.65x, slightly higher than '22, but actually right around the target leverage for the current mix of our business. With respect to growth CapEx, we have a midpoint of $1.55 billion and a fairly wide $300 million range between the low and the high. This is a wider range for us for CapEx and really just reflective of some of the producer growth uncertainty that's out there right now, especially on the gathering and processing side of the business. We're planning on $550 million of traditional maintenance capital and $250 million of regulated emissions reduction program CapEx. Finally, somewhat as a side note, and with respect to cash taxes and update there, lots of developments really still coming together on the new book minimum tax. But based on what we know right now, we would -- we could have a book minimum tax of up to $200 million in 2024. Again, no book minimum tax expected in 2023, perhaps up to $200 million in 2024. And again, any amount that we would pay in 2024 under a book minimum tax can be used to offset the regular cash taxes that we already expected to resume in 2025. So perhaps a little bit of an acceleration on part of the taxes in 2024. Okay. So let's take a closer look at that EBITDA growth. $6.6 billion of 2023 EBITDA will generate a 7% CAGR for the company from 2018 through 2023. Now looking at the drivers on the right-hand side of the slide, we'll see a full year from both of our acquisitions that closed in 2022, Trace and NorTex; as well as 10.5 months for the MountainWest Pipeline acquisition that closed last week. We are expecting modest gathering and processing volume growth spread across a few different areas, really led by the Haynesville, some growth in the liquids-rich areas of the Marcellus and Utica as well as the Wamsutter and DJ areas out West. We expect to see continued strong earnings for our gas and NGL marketing business. So it does look like, to us, in 2023, we'll once again easily beat the $50 million to $70 million run rate that we've previously discussed for the Marketing segment. We'll see some favorable inflation adjustments to our gathering and processing fees. And we also have some attractive hedges protecting our commodity-exposed gathering and processing fees in the Barnett area. Now some of these hedges were shifted over from our Haynesville upstream business at year-end as we explore the potential sale of those assets. And with respect to the upstream operations. Using the February 8 pricing, we are expecting around $330 million of EBITDA for the combined Haynesville and Wamsutter upstream positions. At this point, this is the biggest direct commodity price impact we are seeing in the business. And we've ranged that guidance, plus or minus $100 million around that $330 million midpoint. We've also included a commodity price sensitivity slide for the upstream business in the appendix. So overall, our expectations for slower EBITDA growth in 2023 really align with our expectations for a lower average natural gas price in 2023, including lower producer drilling activity this year. So let's turn the page and take a closer look at the CapEx guidance. Here, we have a pie chart showing the breakdown of our CapEx at midpoint. As I mentioned earlier, we do have a wider $300 million range on our growth CapEx this year. The biggest drivers of where we'll end up in that range are most likely linked to the producer activity that we see in the Haynesville and the Northeast next year. At the $1.45 billion midpoint, growth capital is pretty spread out across the business. It will be led by work on our Louisiana Energy Gateway Pipeline project and the related Haynesville gathering system expansions that Micheal discussed. And he also discussed that we do have a lot of contracted growth in our transmission in Gulf of Mexico business. The 2 largest projects for spending next year will be Regional Energy Access as well as finishing up work on the Shell Whale project as well. In the Northeast gathering and processing business, we'll see continued expansion projects, led by the wet gas systems of the Ohio River Supply Hub area, but also we'll be finishing up the expansion work in the Northeast Pennsylvania as well. And we'll see a lowering of spending in our upstream joint ventures in 2023, as our working interest in the Haynesville PUDs has already now shifted lower. In the green slides, you see growth capital associated with our ongoing solar projects and other New Energy Ventures investments. Chad is going to speak to those in a moment. So that covers the combined $1.55 billion for total growth CapEx for the company for 2023. In the darker blue slides, you can see our regulated emissions reduction program capital totaling $250 million. Mike will discuss this investment opportunity with you. But as a reminder, this is basically additional investment in our regulated rate base that will gain a regulated rate of return during our next Transco rate case, which will have new rates effective in March of 2025 or in the case of the emissions reduction program spending that we're doing at Northwest Pipeline, that was recovered by a tracker mechanism that was agreed to in the last rate case settlement. In the purple slides, you see the traditional maintenance capital is at $550 million. And as usual, the majority of that is associated with our FERC-regulated pipelines which in that case, really serves to offset the regulated -- the depreciation of the regulated rate base. So that covers our 2023 CapEx. Now let's shift to a discussion of our capital structure and our capital allocation. No real changes to announce to our returns-based capital allocation approach. First, we highlight the primary importance of protecting the long-term health of our balance sheet and our investment-grade ratings. You saw that 2023 guides to a 3.65x leverage. That's a strong investment-grade leverage level, even after closing 3 acquisitions in the last year. Second, we plan to continue to grow our dividends, paced with the growth in our base business EBITDA while keeping strong dividend coverage. Third, we're pursuing the attractive organic capital investment opportunities that you've been hearing about in our presentation. Fourth, we are investing in the large-scale emissions reduction projects that generate those regulated returns. And finally, with respect to our financial flexibility versus other alternatives, we don't see value in further deleveraging from where we are currently at with the balance sheet. We've talked about stock buybacks, competing with the bottom of our capital investment return portfolio, which would be our regulated pipeline returns at around an 11% return. So generally speaking, where we see a return profile on stock buybacks that competes well with our scalable emissions reduction projects, we'll take action under our currently authorized buyback program. And with respect to M&A, we remain active reviewers of the M&A landscape, but we will continue to be very selective and strategic with these types of opportunities as we really proved out with the 3 acquisitions that we did in 2022 at attractive multiples. Chad will share more about those acquisitions in a moment. So let's turn the page now and take a look at the overall return on invested capital we've seen over these last many years. So our management team is unified and very focused on driving returns on capital in our business. As we've discussed before, our performance equity compensation payouts for our senior management team are materially influenced by improvements in our return on invested capital. And this slide really shows how we've been doing with those recent capital investments. You see the adjusted EBITDA increase, less EBITDA from assets that we've sold, is up $1.59 billion from the 2019 to the midpoint of this 2023 guidance. That $1.59 billion increase is about 17.5% on the $9.1 billion in capital that was invested by the company in 2019, '20, '21 and '22, plus the $1.5 billion MountainWest Pipeline acquisition price. The 17.5% is somewhat conservatively calculated using the slower EBITDA growth that we're expecting in our '23 guidance. But it does illustrate the effectiveness that we've had in achieving our organizational goals of disciplined capital spending, seeking strong incremental returns, excellent project execution with continuous improvement in the operating margin percentage that Micheal spoke to and the resiliency really of our natural gas-focused business and strategy. Let's look at how this return on invested capital performance has impacted our balance sheet strength and financial flexibility. On the left-hand side, you see our very manageable debt maturity profile for the company, which does now include the $430 million of debt that we assumed in the MountainWest Pipeline acquisition last week. For 2023, we only have $600 million of 4.5% notes maturing this year in November, but are callable at par in August. Additionally, we do have $1 billion of 4.3% 2024 notes that are callable at par in December. On the right side of the slide, you can see the great progress we've made on leverage, resulting in solid and stable investment-grade ratings at all of the ratings agencies. You can see our fixed rate debt portfolio has an average coupon of 4.77% at an average maturity of just under 12 years. Now last August, we issued $1 billion of 10-year notes at a 4.65% coupon and $750 million of 30-year notes at a 5.3% coupon in an offering that really had tremendous demand. So we are confident we will continue to have strong access to debt markets at relatively attractive rates with our business. Finally, we continue to maintain a strong liquidity position with our $3.75 billion credit facility. Now let's take a look at the drivers of our growth beyond 2023. As we've discussed, we're coming off record growth in 2021 and 2022. And we've now reviewed our drivers for growth for what will likely be slower growth year in 2023. But as we look into the future, we see another breakout year coming with so many business drivers coming together in late 2024 and into 2025. We see all of this leading to our confidence in our continued long-term adjusted EBITDA growth target of 5% to 7%. So before we close, let's review the drivers of that growth. In our Transmission business, we'll have favorable rate cases, incremental expansions and acquisition impacts that should drive substantially higher 2025 adjusted EBITDA. In the Northeast and West gathering and processing businesses, system expansions, new takeaway and in-basin demand should drive higher gathering and processing volumes, along with the full year of the Louisiana Energy Gateway Pipeline project in 2025. In the deepwater, we have 6 major deepwater projects underway that are expected to double Gulf of Mexico adjusted EBITDA by 2025 from the 2021 level. And in a moment, we'll hear more from Chad about the next generation of growth opportunities for our company. So in closing, thank you very much for your time and attention this morning. Williams is a unique investment opportunity. And we continue to be exceedingly focused and unified toward achieving our goals. Our unique natural gas-focused strategy is centered around valuable and irreplaceable assets, and it continues to generate growing high-quality cash flows. We've had 10 consecutive years of adjusted EBITDA growth across a period of time when natural gas price was typically low and stable. And we've had a history of meeting or exceeding Street estimates as well. When natural gas prices and volatility increased, it quickly led to our breakout year like 2022. But we've generated an 8.5% adjusted EBITDA CAGR for 2018 through 2022, and we see growth continuing and expect another breakout year coming in late 2024 and early 2025. We have a strong balance sheet and a strong record of dividend growth and coverage. Looking at 2018 to 2022, we've had a 6% CAGR in our dividend while increasing our dividend coverage by 11% or 0.24x. And as we've heard about earlier in the presentation, we're also proud that we're outpacing the industry across key sustainability rankings as well. So with that, I'll turn it over to Chad. Thank you.

All right. Thanks, John. So as you've heard from Michael, John and Alan, this is really a great time for Williams. And we are truly well positioned as a leader in the evolving energy landscape. Our teams and employees have been extremely focused over the past several years. We've built an incredibly solid foundation and have established Williams as a true leader in the clean energy economy. I'll touch on a few highlights of our strategy, including our track record of recent successful transactions, our focus on the natural gas value chain and our expanding wellhead-to-water strategy -- wellhead-to-market strategy. And I'll also talk about our continuous evolution as a business to ensure sustainability for generations to come, while also leading the industry to new solutions that solve our world's greatest energy problems. So let's take a closer look at our philosophy and recent accomplishments on the transaction front. Our approach to transactions is straightforward, but it's, by no means, easy. It requires a disciplined approach that begins with our constant development of our fundamental view, which we use to guide our strategy work. Our strategy efforts are deliberate and set very clear focus areas for us. We constantly assess market fundamentals, both near and long term. We look for where value exists today, but also for where we see it expanding into the future. We're always looking to leverage our scale, our capabilities and our ability to seamlessly integrate businesses into Williams. And we seek transactions with long-term potential that will not overstress the balance sheet. And we always strive to strengthen the company's platform and our ability to drive future energy solutions. It may surprise you to know that from a headline value perspective, we've actually sold more than we've bought over the last 5 years, even when we include the recently closed MountainWest transaction, which closed a week ago today. We've strengthened the portfolio by recycling out of non-core assets and into better-fit platforms. And while we sold more than we bought, we've significantly grown earnings during this time period by selling at high valuation points and buying new businesses at relatively lower valuation multiples. In fact, many of these acquisition multiples are akin to build multiples, but they come without the negative carry that you get with multiyear projects and the associated capital risk. These investments deliver immediate results. The primary way we achieve these results is the old-fashioned way. We don't focus on near-term merger math. We break down every business that we own, every target that we evaluate. We build long-term cash flow models. If we own an asset that doesn't help accelerate our strategy, we are always open to high-grading. And for targets that we evaluate, we make sure that those acquisitions compete for capital with a sharp focus on generating long-term results and an attractive return on invested capital. And in 2022, we continue to add great assets at attractive values. Importantly, these assets fit squarely within our strategy and are supported by very strong long-term fundamentals. It's also important to note that in 2022, we generated significant cash flows from transactions that we closed in 2020 and 2021, in particular, in the upstream and marketing businesses, and we were able to reinvest those cash flows into these highly contracted long-term platforms. Trace Midstream expands our footprint into the prolific East Texas Haynesville, tying directly into our wellhead-to-water strategy. Trace increases the scale of our footprint by 2.5 Bcf a day of gathering and treating. And prior to Trace, our Haynesville footprint was entirely focused on the Louisiana extent of the Haynesville Basin. And East Texas -- Trace extends us now into East Texas, and the East Texas extends to the Haynesville is no joke as well. Our largest producer customer behind the trace system has consistently delivered many of the largest and most productive wells in the Haynesville. We see single-well initial production rates of over 30 million cubic feet a day. And to put that into perspective, that amount of ongoing production can heat almost 150,000 homes a day, one single well in the Haynesville with the potential of heating 150,000 homes. So the efficiency and the productivity of the Haynesville, coupled with its proximity to the Gulf Coast and the LNG markets, is why we expect to see long-term value from these assets. As you've heard, NorTex added 80 miles of transmission pipeline and 36 Bcf of storage to our footprint in the Dallas-Fort Worth region. And I'll reiterate that this is a region of declining native supplies, but one of the fastest-growing power and gas demand markets in the United States. Barnett Shale supplies have declined by over 1 Bcf a day over the last 5 years, while gas and power demand has continued to rise in the DFW Metro area. This fundamental backdrop creates a significant value driver for storage in the region. And as electricity markets will increasingly rely on natural gas for dispatch to balance loads, storage will be one of the most critical assets in tightly balanced markets. And finally, MountainWest adds roughly 2,000 miles of pipeline and interstate systems across Utah, Wyoming and Colorado, with 8 Bcf a day of transmission capacity and 56 Bcf of storage and the largest storage field in the Rockies. This acquisition enhances our position in the Western U.S. and is complementary to our current footprint. And we'll take a little bit more of an in-depth look at the West on the next slide. So looking at the West, you see here that we drop MountainWest into our Western footprint and truly create a critical gateway between markets. MountainWest fits squarely within our existing footprint of upstream, midstream and downstream pipeline and storage infrastructure. And this footprint includes, as you've heard, our large-scale Wamsutter footprint as well as our extensive gathering and processing across the Rockies. And as Alan showed, wind and solar capacity grew significantly, over 85% within our Northwest corridor from 2019 to 2022. And during that time period, we've seen higher utilization of our gas and storage assets. We're seeing the proof that the expansion of intermittent renewables is only possible with the partnership of providing a reliable gas pipeline and storage backbone. In fact, over the past year, we've seen gas price dislocations of over $50 in MMBtu across a distance of less than 200 miles, a distance that is straddled by these assets here in the West. So this structural imbalance will only get worse. As demand for energy continues to rise in the West, you see on the map the main sources of reliable energy all exist East of the Rockies. And so our goal is to expand the ability to serve Western markets and provide the critical infrastructure that will be necessary as Western states continue to increase electrification and pursue low-carbon energy solutions. And now let's shift our focus to the South and provide an update on our wellhead-to-water strategy. The Haynesville provides a great example of the integration of the natural gas value chain and the benefits that it brings for us and for our customers. It truly is a first-of-its-kind showcase of how the U.S. can source, transport and deliver the cleanest end-to-end energy on the planet. We can produce energy in Louisiana for consumption in Europe or Asia, and we can do it affordably, we can do it reliably. And importantly, we can demonstrate the integrity of the global emissions benefits. Over the next several slides, I'll step through several of the components of our Gulf Coast wellhead-to-water strategy. And how, by putting these pieces together, we're creating a very unique product. First, starting with the front end of the wellhead-to-water value chain, our upstream partnership with GeoSouthern has been incredibly successful. In fact, in just under 8 months, we've grown production in South Mansfield by almost 50x, exiting 2022 with almost 600 million cubic feet a day of production. To put that into perspective, if we move that 600 million cubic feet a day of production just from our South Mansfield footprint to Europe in the form of LNG exports, that would be enough energy to power 3.5 million European households, 3.5 million European households just from our South Mansfield production alone. And by displacing European coal consumption with that 600 million cubic feet a day, our South Mansfield production could remove approximately 13,000 metric tons of CO2 emissions annually. From an upstream ownership perspective, as you've heard in January, GeoSouthern surpassed a key milestone in lateral [indiscernible] completed. And they've worked their way, performed exceptionally well, worked their way into our prestructured equity reversion. So our upstream exposure will now decline over time significantly while the midstream and downstream benefits will continue to grow. And for wells completed in 2022, Williams owned approximately 70% of the partnership interest in those wells, which equated to about 50% of the net royalty interest. On a go-forward basis, Williams will own 25% of the partnership interest, and GeoSouthern will own 75%. So our CapEx requirements will be low, our cash flows will be attractive, and the net upstream exposure to Williams will continue to decline over time. And now let's move a little further downstream in the Haynesville. Our South Mansfield volumes have grown rapidly. Our gathering and treating footprint has expanded into Texas with the Trace acquisition. And as Micheal detailed, our legacy systems in Louisiana have been growing through additional expansion projects. In fact, if you unraveled the pipeline that we currently operate in the Haynesville and stacked it in a straight line, it would extend from here in New York City all the way to St. Louis, Missouri. We've got a large footprint that we've established now in the Haynesville. And Louisiana Energy Gateway will provide another critical extension of this footprint and will create a bridge between the Haynesville and growing LNG markets. The project has an initial capacity of 1.8 Bcf a day and is expandable to over 2 Bcf a day with compression projects. And Louisiana Energy Gateway will gather Haynesville gas truly from across the entire basin and will make deliveries into Transco at Station 45 at Gillis, Louisiana, which has become a critical supply hub for LNG terminals located along the Gulf Coast. Louisiana Energy Gateway scheduled, as you've heard to come in service in late '24. And as part of the project, we're designing and deploying advanced emissions monitoring and certification technologies so that we can provide low-carbon next-gen gas deliveries into Gillis. And as I'll show on the next slide, with a complementary carbon capture and storage project, we're truly designing Louisiana Energy Gateway to be net zero -- to have the potential to be net-zero infrastructure. So as I mentioned, alongside LEG, we're designing a carbon capture and storage project, shown here on the slide, that targets the removal of a minimum of 2 million tons of CO2 from the Haynesville basin each year. Our goal is to gather CO2 from across our gathering footprint, aggregate that CO2 and move it to a large-scale treating and removal facility. And from that facility, we'll transport the pure CO2 via pipeline to a storage facility and store it permanently underground in Southern Louisiana. Haynesville production is already one of the world's most efficient sources of energy. And on its own, Haynesville production and natural gas will displace foreign coal and drive down global emissions. But with emerging technologies like CCUS, we can take the benefits of natural gas even further. Imagine this, by coupling CCUS with the LEG project and removing an additional 2 million tons of CO2 from the energy value chain each year, that has the same effect of adding 500 wind turbines running constantly or 33 million trees that grow for over 10 years. I mean, it's a huge opportunity and impact that we have by decarbonizing the natural gas value chain. So with our efforts in the Haynesville, we intend to deliver the cleanest, lowest carbon natural gas possible to the doorsteps of the LNG market. And here on this slide, you see that doorstep. In the first half of 2022, the United States became the world's largest exporter of LNG, only 5 years after first LNG exports began along the Gulf Coast. And forecasts vary, but by 2040, we expect the U.S. to export almost 40% of the world's demand for LNG. And as you can see, Williams is really well positioned to deliver clean natural gas to LNG terminals along the Gulf Coast. There are more than 20 Bcf a day of projects that are either in service or under construction within our footprint and another 20 Bcf a day that are awaiting and pursuing FID. So you can see how well positioned our Haynesville footprint is to deliver into the LNG markets as well as the Transco systems' ability to bring gas supplies to LNG export opportunities. And to further integrate our wellhead-to-water strategy, moving another step further downstream, we're continuing to explore how we can provide additional access to international LNG markets. In 2022, we announced a nonbinding HOA with Sempra infrastructure, that enables a seamless value chain that extends all the way from the Haynesville production well to the internationally marketed LNG cargo. And there are 3 primary components to this strategy. The first is a gas sale from the terminal point of LEG into our LNG partner in support of delivering next-gen gas to be turned into LNG. The second is the joint development and operation of pipelines that will further extend from LEG and connect directly to LNG liquefaction terminals along the coast. And the final component is an LNG offtake agreement that will allow us to market LNG to international buyers on behalf of our producer customers. Completing the build-out of the wellhead-to-water value chain allows us to offer international market access to Haynesville producers, and our goal is to leverage our customer base and our Sequent marketing capabilities to broker transactions between producers and LNG off-takers. This allows producers to expose a small portion of their production to international prices and allows international buyers to gain direct access to U.S. producers that are seeking to sell their gas on an international price index through back-to-back transactions that we can help facilitate. And now let's shift a bit of focus to gas and NGL marketing. I'll touch briefly on our strategy here. I think it's always helpful to remind ourselves of how Sequent is set up and how we make money. Sequent has been a great addition to the business after only being a part of Williams for now just less than 24 months. You've heard, I think, a lot of the benefits already today. As we've discussed many times, Sequent combined our legacy gas and NGL footprint with an existing large-scale gas and pipeline storage optimization platform. And today, it has become a seamless fit, and they now both operate on one common platform. So we have a single marketing and optimization platform at Williams. And Sequent is focused on several key strategic pillars. Sequent monitors market fundamentals and is constantly tuning a portfolio of pipeline and storage capacity to establish valuable base positions with expected upside. It's important to remember that Sequent does not create speculative commodity trading positions, but instead looks to contract for pipeline and storage capacity that have inherent or intrinsic value with downside limited only to the capacity fees that we pay for that capacity, not to potential changes in commodity price. The team works hard every day to build these strong regional portfolios and to build deep customer relationships. And as daily prices change across the geography of our pipeline positions, our teams optimize those positions and capture those price changes only when they present upside opportunities. So we can be very patient and disciplined. We protect the value that base transport capacity and only execute on additional trades when upside materializes. And likewise, with storage, Sequent contracts for storage that has inherent value and downside limited to the storage fees that we pay, again, not exposed to commodity price changes. But when we see price changes over time, over storage seasons, we can optimize our storage positions and execute trades that capture value when the price difference between seasons exceeds the cost of our storage positions. So Sequent provides a low-risk platform that creates exposure to upside when markets are volatile across geography and time. And Sequent increased our marketing footprint to approximately 8 Bcf a day, with reach truly across the entire North American gas market. And with a portfolio of over 1,400 customers, the team has truly created a diverse and balanced platform that has been proven successful under a wide range of market scenarios. And 2022 was a great example of this balance and diversity. Sequent delivered, as you heard, over $250 million of EBITDA last year. And we were able to generate those cash flows and recycle those cash flows, as I mentioned, into fee-based assets like NorTex and MountainWest. But what's really interesting about Sequent's year last year is that those contributions came truly from across the portfolio. We saw value in the Northeast, where constraints between supply points and Northeast utility markets created value into markets like New York, New Jersey and Boston. We captured value in the Midwest as volatility between Canadian supply and Chicago markets created opportunities. Our Gulf Coast teams optimized constrained supplies in the Haynesville and captured significant value across Transco from South Texas, all the way into Louisiana. And in the West, our capacity positions, as we've discussed, were well placed as a bridge between tight supplies in the Rockies, low storage inventories in the West and high demand in California and the Pacific Northwest. And on top of strong performance across those transportation positions, you've heard that our storage portfolio has also performed extremely well as significant price swings have also led to periods of price dislocation across storage seasons. As we've guided previously, and as John mentioned, our portfolio sets us up for a steady long-term EBITDA run rate of $50 million to $70 million annually with expected upside. But we do expect Sequent to outperform again in 2023, with storage positions expected to, once again, deliver significant value. And as John mentioned, a good portion of that value has already been locked in by the team last year, but we expect it to materialize throughout 2023. And now moving on from Sequent, let's take a look at some of our New Energy Ventures, opportunities and efforts that are underway. Our New Energy Ventures efforts are focused on evolving our core business with clear guiding principles. And as John mentioned, we intend to invest around $100 million of capital this year in New Energy Ventures projects. And we have a nice runway of additional opportunities that we're continuing to evaluate across our capital allocation priorities. In 2023, the $100 million will be spread across a diverse set of projects, including solar, hydrogen, CCUS and renewable natural gas. And on the next few slides, I'll touch on a few of the exciting New Energy Ventures opportunities. Here, on the hydrogen front, we're pursuing projects across our entire footprint. We have 2 projects in the Northeast that are relatively small but are approaching commercialization with utility customers, and we're evaluating additional projects that could further commercialize hydrogen deliveries within our infrastructure. In addition to those types of projects that we're developing directly with customers, Williams is participating in 10 separate applications in front of the Department of Energy, including 6 hydrogen hub applications. I recall that in 2022, the Congress passed, and the President signed, the infrastructure bill, and it included $8 billion for hydrogen hub applications. And we've partnered with key states and industry partners to participate in hydrogen hubs that truly span across our entire footprint. All 6 of our applications were advanced by the DOE in late 2022. And we expect to learn a lot more about the potential for those projects throughout 2023. I think it's worth taking a moment to spend to walk through these 6 applications, just to show the diversity of opportunities that we're evaluating across our footprint from a hydrogen perspective. In the Northeast, we're partnering with Northeast states and utilities in an application led by the New York State Energy Research and Development Authority. And that project is focused on delivering green hydrogen to Northeast gas distribution companies, many of whom are our existing customers. In Appalachia, we're partnering with Pennsylvania, West Virginia and Ohio on a hub focused on hydrogen produced by natural gas and renewable energy and delivered to power plants in the region. In the Southeast, we're partnering with Duke Energy, Dominion Energy, Siemens and the States of North and South Carolina, Virginia, Kentucky and Georgia to explore hydrogen deliveries across the Eastern seaboard. In Oregon, we're partnering with Mitsubishi and local electric utilities to explore delivering pure hydrogen for power production and for long-haul transportation. In the Rockies, we're partnering with the states of Wyoming, Utah, Colorado and New Mexico to explore green and blue hydrogen for power generation, residential, fuel, farming and industrial use. And finally, in the Gulf Coast, we're partnering with the states and industry on the Halo hydrogen hub, which I'll spotlight on the next slide. As part of the Halo hydrogen hub, we're proposing to leverage, what I've talked about, our wellhead-to-water strategy and ability to source and deliver the lowest carbon, cleanest next-gen gas possible and deliver that for conversion into hydrogen along the Gulf Coast. And Williams is working in partnership with the states of Arkansas, Louisiana and Oklahoma with a goal to supply next-gen gas to hydrogen plants and also to leverage our infrastructure to deliver hydrogen blends to homes and businesses across the region. We're convinced that if hydrogen works, and we want to scale hydrogen as a country, the only way we can do so is to leverage the existing gas pipeline infrastructure. And imagine this, if we could have just a 10% blend of hydrogen in our infrastructure in Louisiana, that amount of hydrogen could offset the heating emissions of half of the homes in the state of Louisiana, which is a 10% blend. And while hydrogen is an exciting opportunity for us, there remains no more powerful tool for decarbonizing the globe than through both expanding the use of natural gas and through further decarbonization of the natural gas value chain. Alan already showed that gas emissions in the United States in the past decade -- that emissions in the United States in the past decade, there has been no greater contributor to reducing those emissions than natural gas. And we can do even more. If the industry reduced methane emissions of current operations by another 50%, which we believe is achievable in the near term, we can remove another 100 million tons of CO2 emissions per year. That's equal to permanently removing 45 million cars from the road every day or planting 250 million acres of U.S. forest. That would be a forest larger than the state of Texas. And next-gen gas is critical to making this a reality. In 2022, as you've heard, we completed the first end-to-end certified next-gen gas delivery in partnership with Coterra and Dominion, and we're seeing very promising demand for additional transactions for next-gen gas. We're leveraging sensor and measurement technologies. Our software implementation with Context Labs and Sequent is facilitating commercial transactions across our footprint. On the next slide, I'll show a few of the recent technology investments we've made to further advance our next-gen gas strategy. You see here, as part of our clean energy pursuits, we've talked about the fact that we've been evaluating and investing in technologies that can be a force multiplier for the New Energy Ventures' opportunities that we're pursuing. And on the next-gen gas front, our Context Labs investment and partnership remains a critical fabric and deployment across which all of the pieces of the decarbonization puzzle will interact. We've made an additional investment in LongPath technologies. This is a laser technology that can accurately measure methane across long distances. We're implementing LongPath technologies at several of our Williams' operating sites. And we recently announced another investment in a satellite monitoring technology, OSK, or Orbital Sidekick. And OSK will launch several satellites later this year and will start monitoring Williams' facilities. And to take next-gen gas at the next level, as Micheal mentioned, today, we announced that Williams joined the United Nation's Oil and Gas Methane Partnership 2.0 or OGMP 2.0. OGMP 2.0 is a global initiative designed to improve the energy industries' methane emissions reporting. And OGMP 2.0 creates a consistent platform for encouraging progress in reducing global emissions. As the first U.S. pipeline company to join OGMP 2.0, Williams adds this commitment to our suite of standards in support of our next-gen gas strategy that will continue to drive transparency and decarbonization of the natural gas value chain. We believe that this program, our next-gen gas program, and its multiple layers of advanced emissions detection and measurement technologies, including aerial and satellite imagery, coupled with our Context Labs, emissions registry and analytical capabilities, we believe this is the only natural gas certification program that is designed to exceed OGMP Level 5.0 at scale, which is the gold standard for measuring, tracking and certifying the emissions of an energy system. So by continuing to raise the bar and tracking and lowering emissions, we can encourage others to follow suit, and we can show with credibility how important natural gas is to decarbonizing and meeting the world's energy needs. So I'll close by reiterating what you've heard many times today, and that's just how powerful a tool the natural gas can be for our country's energy and decarbonization needs. Natural gas is key to helping the U.S. improve trade balances, to be a leader in carbon reduction as well as support the growth of renewables. And we truly believe the golden age of natural gas should be here because of what it can do for our world. And it's our responsibility to advocate and tell the story to not only you all here in the room but to people all over across the country. And I'm really proud of the work that Williams is doing in this space, not only to tell our own story but to elevate the industry as well. Just one quick example is our work with an organization called Natural Allies, an organization that was stood up in large part due to the efforts at Williams. Frankly, in large part, thanks to Alan's leadership. And what started as a modest effort has truly become a bipartisan effort and campaign to showcase the role of natural gas in a clean energy future. And I'll add that this isn't just a bunch of gas companies singing the praises of natural gas to one another and to ourselves. We're very grateful to work alongside many leaders, including Senator, Mary Landrieu, Congressman, Tim Ryan and leaders within union and labor organizations as we educate and advocate for common sense real-time solutions. So be sure to check out Natural Allies for a clean energy future. And with that, I will pass the microphone back to Danilo, who will set us up for the next portion of the program.

Thank you, Chad. We'll take a brief break and try to get back here around 10:50 or so. Upon which, we'll start the Q&A session. Thank you. [Break]

All right. Now that we've got enough chairs for all of our executives, we can get started with the Q&A session.

Brian Reynolds from UBS. Perhaps maybe to start off on just the base business growth over the next 2 years. Prior to Trace, MountainWest and NorTex, it was hard for investors to kind of see any base business growth, particularly post the REA delay at last year's Analyst Day. Now with all the aforementioned assets included in the portfolio and partial potential in-service of REA in '23, you alluded to some small green shoots of growth. And thus, my question is more around the '23 guidance. Could you just perhaps give some assumptions around the low end and high end of that EBITDA guidance, as it seems like there's already some assumptions around some lower activity level given the headline in net gas price.

Yes. Thank you. I'll hit that at a high level, and then turn it over to Micheal to talk about some of the specific drivers. But yes, you picked that up correctly. We did pull back from where our plan was earlier in the year. We saw gas prices to give ourselves some room for a less robust environment in gas. So I'm glad we had 1.5 months here to see what gas prices are before we set them, but we certainly pulled it back pretty hard as a result of seeing that. We haven't had the producers telling us that yet, just to be clear, but we've been through these cycles a few times. And so I would say we're prepared for a less robust development. But we do have some areas like Micheal mentioned, like the Blue Racer Midstream interconnect, which is basically pulling volumes back to our system that were going off to others for processing. So with that interconnect, we've now got capacity on Blue Racer Midstream. And I think as well, you're seeing our margin continue to increase in the Northeast because so many of those contracts have inflation adjusters in them. So even with flat volumes, we're still seeing margin improvement in that business. So Micheal?

Yes, sure. I would add to that. We're seeing strong NGL pricing still. So I think you're going to still see some capture that we have in the rich gas play. So we're fairly confident in regard to that. Some of the dry gas areas -- I don't think my mic is on. Somebody check my mic on. So I was saying, the rich gas, it will be an upside for us this year because of the NGL pricing strength that we see there. Can you hear me okay? Thank you. I'll just hold it here for a moment. Sorry about that. And as Alan said, we're just now starting to see the producers coming out with their plans for the coming year. They typically wait until about this time. And the conversations we're having so far, we feel very good about the NGL play and the rich gas. Dry gas, for us, we -- as Alan said, we've seen these cycles many, many times, and we have a lot of confidence that the summer will be strong. We saw that last summer with power generation and a very substantial need for natural gas to support power generation last year. And really not a very strong cooling degree day summer for the most part last year. And there's a lot of coal-fired generation that's coming off the grid this year. And many of those units were very high-capacity factor units, and that's going to bode well, I think, for the summer season. So we'll have to see how that plays out. But certainly, we've got a lot of diversity in the business now. And these low gas prices give us an opportunity to fill our storage at very favorable prices at this time. So we'll take advantage of that as well.

First of all, feel better, Alan. I guess you'll have to come back for the Manhattan gastronomic tour year. So I had a question maybe on the criteria for share buybacks. It seems like it's evolved a little bit over time. It seems like it's still opportunistic. Can you talk, maybe, John, about comparing it to a regulated return as the criteria versus I guess Williams' entire business mix? And then I'm also curious, you've surpassed your balance sheet goals and targets. Is there still a ceiling there? Would you also be willing to deploy the balance sheet should there be a dislocation in the share price?

Yes. I think what we're saying about the share buybacks is that it just falls in as part of the overall returns-based approach that we're taking to capital allocation. And so we we're stacking all of our opportunities, and we're looking at what is really that floor level of opportunity, which we see as our regulated rate base investment, that discretionary investment that we can make into the regulated rate base with the emissions reduction program. I think that's a pretty unique thing about our business is that we do have this very large pool of discretionary capital that we can invest at attractive regulated rate returns. So I think that's always there. If we do see a pullback in the stock price, like what we saw at the end of the third quarter, we have the authorized buyback program. We can quickly take action to buy back shares when we think that, that competes well with that 11% or 12%. And I think there's a lot of different ways to look at the return on a buyback, many different kind of techniques. Some were sort of speculative than others. I mean, a real simple way to think about is the dividend you're taking out on day 1, which today is 5% plus yield, plus our 5% to 7% long-term growth that we feel really confident in our ability to deliver. So where you see things that compete up against that 11% or 12%, we think that's a good time to maybe take some action there. I think on the leverage 3.65x guide in 2023, I think, is a pretty good place for the mix of business. We do still have some upstream, not as much, only $230 million -- sorry, $330 million at midpoint. There is some marketing EBITDA in there as well. So I think it's a safe leverage area for the current mix of business at this 3.65. Doesn't say we wouldn't use some capacity under certain circumstances, but I think we're pretty happy with where the leverage is at.

John Mackay, Goldman Sachs. I wanted to start on REA, just congrats on moving it forward, getting the state permits and everything. Wondering -- I want to talk about 2 things. One, maybe the gating items on how to get comfortable with, whether or not you can hit the construction time line for '23. I think you need the FERC to come back by March 3 or something. Maybe you could talk through that. And then on a related note, just how you're thinking about CapEx and the guide right now. And whether or not that kind of shifts depending on this FERC time line?

Yes, Micheal, do you want to take the first question?

Yes, thanks for the question. Right now, the gating item is we're awaiting FERC to provide us permission to do tree clearing. And that's the window of opportunity we have between now and the end of March. And we made that request weeks ago. And really, there's no prerequisites outstanding in regard to that. The FERC rehearing process is closed. They need to make decisions on rehearing, and they can wait 30 days to make those decisions. And so we feel fairly confident that FERC will act in time for us to start that tree-clearing window, but we did request that permission by March 3, so that we can hit the end of March. And this is all mechanical, hand felling of trees, chainsaws, no mechanized equipment. And so it's -- we've evaluated the amount of tree clearing we need to do there. And if we have to apply more crews to that, we'll do that. But that's really the main gating item right now, is waiting FERC's decision.

I think as far as -- go ahead.

I was just going to mention the capital. Right now, we don't have the acceleration embedded in our capital from a growth standpoint. If we did accelerate construction this season, it would be about $200 million more of growth CapEx we'd deploy this year.

Yes. And I would say broader on the CapEx side, we've got that range in there that's pretty sizable. And really, that is driven by how fast we see drilling activities in places like the Haynesville. We've got a lot of projects, as Micheal mentioned, that we're finishing up. But a lot of continued expectations for growth that's in the capital budget that obviously would pull towards the lower end of the range. So that pulls back, move toward the higher end, if things continued on the path that they're on right now.

Praneeth Satish, Wells Fargo. Two regulatory questions here. Maybe this is for Lane. I guess the first is just the latest on the lawsuit with Energy Transfer, next steps and potential path to receiving proceeds? And then second, just curious for your take on permitting reform, what you're hearing and whether you see a path there for a bipartisan solution?

Yes. Thanks. On the lawsuit, I've always said we feel good about it. It's with the Delaware Supreme Court right now, and we think we'll have a decision by the end of the year, but I don't want to get out over our skis. I mean they have the final say, but we've always felt good about that case. On the permitting reform, there's a lot of incentive on both sides to get something done. And if you spend some time in Washington right now, you can sort of sense that. The Republicans would really like to see pipeline permitting reform and reform on the production side. Democrats would really like to see reform on the renewable side. I mean a lot of renewable projects have a harder time getting permits than we do, and that's pretty stunning. I think it will be led by the house. And then the question is, can the senate come back with something that makes sense, that's meaningful and that the house can live with. And if that's the case, I think you'll see a fairly large number of Democrats go on board enough to get it passed, and I think the President will sign it. So I'm cautiously optimistic that it could happen this year.

By the way, congratulations on your call on the fourth quarter number. I was pretty darn close.

JR Weston with Raymond James. A couple of questions from me. Maybe the first one, just inflation impacts of the business a lot of different ways with positive and negative. One angle, we haven't heard a whole lot of discussion of maybe is talent retention and that side of the business. So curious on any trends there? And then I guess, a second one for me, if I could. A lot of discussion today on the environmental angle. I think we feel pretty good on the governance side. Would be curious to hear a little bit on the social aspect of things at Williams, what you all are doing, both with the company and then also, I think community outreach something really important for this space as well. So any comments on either one of those would be great.

Yes, I'll take the talent retention. So we were very fortunate last year that our turnover was about 7.5%. I know others in the industry experienced more turnover than that. And so I think we were fortunate, but we did lose some. Mostly, those employees stated that they left for better opportunities, more compensation, but we have a very robust compensation, total rewards program, and also to your point on social justice and things like that from a diversity and inclusion standpoint, training programs that we have, opportunities that we have, we've really been trying to be progressive in this space to stay up and allow our employees to have opportunities to grow. We implemented gigs this past year to allow employees to take short-term assignments to get opportunities that they might not ordinarily have and to get networking within the business and meet new contacts and mentors. So we're really trying to be thoughtful to retain our current employees that we have as well as recruiting new ones as well.

Jeremy Tonet, JPMorgan. Just wanted to touch base, I guess, with the -- looking out further than '23 and how you see the earnings power of this business progressing, I think '24 might be a little bit slower, '25 might be a little bit stronger. But just net-net, what do you think is the EBITDA growth potential here over time and how far out do you feel comfortable, like us looking out?

Well, I think you're right, we've got a lot of big catalysts that will hit in '25. And certainly, that's going to be a big driver for '25. But we have a lot of small projects. I think somewhat that's going to be -- if you were asking me this at the first of the year, I would have said, yes, it might be a lower growth rate into '24. But the fact that we pulled '23 back as hard as we did as a result of low gas prices, and expecting activity ultimately to pull back will give us some run into '24 to the degree that we see gas prices and producers respond to that. So I think we'll be a little bit dependent on that. But in terms of contracted capacity, we have a lot of contracted capacity coming on in '25 and certainly, the deepwater is a very substantial pickup with a very solid floor of business across the rest of the area. So I feel pretty good about that. I think some other areas of growth like you heard me mention, our Washington Gas storage and getting that out from a deregulation. We think there's a lot of value in getting to market-based rates on that business. And we also feel like there's pretty substantial value as we're looking forward right now in all the storage that we hold at Sequent. And so we think there's pretty good value to come out of that business as well that we're not planning on to another year like we had in '22. We're not planning on that in '23 right now. But things are shaping up pretty good right now actually for a good year.

Just one more real quick. And I think should over the past 5 years, EBITDA growth is compounded at about 6%. We haven't necessarily seen the stock price, I guess, moving in line with that. I guess -- any thoughts there on what the market is missing, why you haven't seen the corresponding move?

I'm just going to ask you that, Jeremy. Yes, I don't know. I mean, I think this year, gas prices softening up the way they did, I think have kind of taken a little bit of luster out of the space. But it really is hard. I mean, I have a hard time understanding that because we've proven we have a very strong floor in our business through the pandemic, we showed our ability to grow even in that environment, we showed the kind of upside that we have in our business in this last year and we've shown our ability to execute and get things permitted in a way that a lot of people have not been able to do. So it's very surprising to me because when I think about all the things that could go bad, if I'm an outside investor just thinking about where I'd want to place money in things that are stable and durable in this environment where there's a lot of unknowns and rising interest rates, I would absolutely be looking for high-yielding dividend that's got really good growth in it and one that's proven its durability. And I think we checked the boxes on that. So I don't know what else to do other than continue to execute the way we have, but I certainly have the same question.

Jean Ann Salisbury from Bernstein. On Slide 57, you list several Northeast G&P gathering expansions. I just want to check if one in Susquehanna is tied to an early start of REA and then you would get more when the full REA comes on. And then the rest of them, is that kind of rich gas taking more share? And do you expect that to continue over the years?

You want to take that one please?

So the [ Olympus ] program that we're building for Coterra, we made that agreement last year. We started that work. And if you recall, all of our expansions with them, we get a rate increase across all of our volumes. So we're already enjoying a rate increase there before we even deployed any of that capital. It really is not tied to REA whatsoever. I mean, I think opportunistically, we'll take advantage of that, but it had nothing to do with REA being built. They're not a shipper on REA. And so really, it will unlock capacity not only from Susquehanna County, where Coterra is, but Bradford County, where Chesapeake and others are generating some very prolific volume growth that we've seen in previous years, and I think this will just unlock more capability for that as well. So it's really not tied to anything, but we know we hear a lot about Northeast takeaway and the constraints. This is 800,000 dekatherms of capacity that will be going right to very lucrative markets, and we do think there will be a producer response to that once we're in service. And now that we have permits and the project has been derisked, I suspect you'll see some folks thinking about, "Hey, I need to take advantage of this when this comes online".

That makes sense. And then as a follow-up, Alan, your opening comments about renewables intermittency, driving more demand for gas capacity. I thought they were really thoughtful. When you talk to utilities that are your customers, do they -- I mean, do they kind of share the same view over the next 5 to 10 years that they need more capacity factors to make up for the intermittency and that gas is going to be the big balancing factors? There are a lot of difference in opinion, I guess, how that expands?

Yes. Well, it depends on if they're on TV or if you're talking to them in person. But I would just say that they very much believe that gas is -- they understand that gas is what they're dependent on and for most part, if you look at their long-range plans and their resource plans that they file with the utility commissions, most of them are very reliant on natural gas. And so they get it. It's just very hard for them to depend on it, being able to rely on the growth in it when the projects are getting stopped. So we spend a lot of time -- Micheal's, commercial's team at Transco spends a lot of time with them trying to understand how we can get the next 150 million and the next 200 million a day of capacity, and that's what you see in a lot of those projects that continue to come on. But yes, they understand there's really not any other practical solution, and they certainly don't want to be the ones that are explaining why they were counting on the window below and sun to shine and it didn't. I mean they understand they've got to have that long term. So I mean I think a lot of people are hopeful for power storage. And I do think that, that will ultimately have some degree of impact, but not in a way that people can completely depend on dispatchable power, and I think that's where gas is going to come in. But I don't -- the utilities tried. Dominion and Duke, both tried to build a big project into their backyard. And so it's not like they haven't worked really hard at trying, but I really want to stress that we originally had a project that would have utilized some of the Transco right of ways to deliver into that. They wanted to build it themselves. Kind of similar situation with Mountain West. Mountain West wanted to cross at a location we didn't think made sense to cross. And so we backed out of that project because we've been at this long enough, we understand where those risks are and now we're kind of back to where we were 7 or 8 years ago, which is we're going to have to expand along our existing right of ways to meet those demands because that's really the only way you can get something permitted. But that is kind of where we are. And it's a good -- really good question. The utilities would like nothing more than to be able to depend on that. And at this point in time, they really just don't see that they have any other choice at this point.

Craig Shere with Tuohy Brothers. So I hope I do this well. I want a 30,000-foot question weaving together some of the things already asked, like Jeremy's EBITDA growth and the stock relative underperformance, some of the permitting and permitting reform questions. And at the heart of it is what exactly is in the 6% forward average CAGR? That's obviously not priced into the stock. The Street estimates, if you take it out 3, 4 years or not, at a 6% EBITDA CAGR. So how confident are you without transmission debottlenecking, without further major tailwinds from some of Chad's efforts and M&A, vertical integration and maybe some benefits from next-gen low-cost gas that might catch a bit, God forbid. So without any of that, just steady Eddie with what you got. Kind of think of it like Sequent at $50 million to $70 million a year, but sometimes we could do $250 million. So is the 6%, the $50 million to $70 million a year at Sequent kind of analogous, that's our steady Eddie, we can do that, We don't need these tailwinds, but maybe we can do 8%, 9% if everything goes our way?

Yes. No, that is the case. I mean, the business we have that will drive that growth is contracted. So it's not like we're speculating about where that growth is going to come from for the next 3 years. Get beyond that and yes, then we're going to be dependent on things like debottlenecking southbound capacity on Transco, more LNG. But I would say here in the next 3 years, it's very clear to us where that growth is coming from, because it's a business that we've already contracted and it's a matter of getting it built out. So I mean things could happen like we could see some type of delay in the deepwater or something like that. But I would say we've got that in there, pretty conservatively right now from a dining standpoint relative to the progress that the producers are making. So -- but those are some things that are out of our control that could happen, but I would say for the most part, it's certainly not a speculative business, and it's certainly not counting on $250 million from Sequent again.

Gabe Moreen, Mizuho. Two quick follow-ups, if I could. On the decision on selling E&P, particularly in the Haynesville, is that just a question of, hey, let the PUDs just produce out over time versus someone coming in and paying a higher price for? But I think is now basically going to be a pretty PUD heavy production profile. And then also on the ERP spend as far as it pertains to the upcoming rent Transco rate case, do you ask for a specific level of ERP spend in the Transco rate case? Or is it really you just want to get the ERP mechanism in place and then you can spend kind of what you think is fitting?

I'll take the ERP question and then I suspect Chad can jump in on the upstream. So really, the mechanism that we'll seek with customers is we'll have this amount of spending per year. That's what we'll commit to. I mean we lay out those compression replacement projects for years to come. I mean, it takes 2 or 3 years to get through that between supply chain issues and everything else, planning for construction. So we'll commit to a certain amount of capital on the Transco system every year, and this is what it looks like. So they know really almost exactly what their rate increases would look like. And that's the exact same thing we did on Northwest Pipeline. We have a limit every year of how much we can put into that emissions reduction program tracker from a capital standpoint with some freeboard, obviously, if we have any overruns to where we can accommodate that and still get the rate increase. So that's the same mechanism that we'll look at for them in the Transco side. So we look to be having about $200 million to $300 million a year in the total program, and the bulk of that is on the Transco system. The opportunities are about -- gosh, about 80% Transco, 20% Northwest Pipeline, I would say, on that $1.3 billion.

Yes. Maybe on the E&P, maybe just first step back, you think about the strategy there, as we've talked about many times, we had latent capacity. We had good quality upstream acreage that wasn't being developed. Haynesville, it's kind of like check, we primed the pump, we helped get that asset into the hands of someone that would develop it, and we have filled entirely. In fact, we've overfilled. We're expanding the South Mansfield position from a midstream perspective. So from a strategy perspective, mission accomplished. And we have been evaluating whether or not it makes sense to exit more rapidly than kind of the reversion that we've got in place would drive. But I would say that we're going to be disciplined from that perspective. I mean the Haynesville will actually kind of exit us fairly rapidly anyhow because of the speed at which those wells decline. And as I mentioned, most of our ownership is tied to the existing production that is now online. And that on a net basis will decline as that existing PDP production declines and the PUD development that will take over the volumes we will have much lower interest in. We'll continue to evaluate, does it make sense for us to further accelerate the exit, but we're going to look at that and say, are we better off harvesting those cash flows, because the market today might not pay us an appropriate discount rate against cash flows that like we know are coming over a period of time. And so that's how we're thinking about it. We are -- but to be clear, I mean, strategy-wise, mission accomplished, if it's better for us to exit more rapidly, economically, we will. If not, we'll continue to be thoughtful going forward. And I would just say that the Wamsutter is a little bit behind from a timing perspective. We've started that development activity with Crowheart, and we're just now seeing some of those early results, but that's always been the goal is to just make sure that those assets are getting the right amount of capital to fill up those midstream systems, and we'll continue to look at does it make sense, have we achieved that goal and is it the right time to further accelerate exiting.

Let me add to that, even though the reversion has occurred in the Haynesville, our partner still has a drilling commitment behind that agreement that we have with them from a partnership standpoint.

Can you just elaborate on how you see the Northeast evolving from the perspective of how much in-basin demand do you think there is that will allow for growth? And Alan sort of touched on it also, if MVP doesn't get built, how do you see the next year evolving also in terms of being able to get gas down to the Gulf Coast to saturate the LNG demand?

Do you want to take that?

Yes. I'll take that. In regard to the Northeast, we had a really interesting development that occurred. There were -- Sequent has an AMA and they have an obligation to serve a power plant where they had negotiated gas supply agreement with them. We were able to put together a path for them to supply that on capacity, they already controlled, go to our producer, buy that gas from that producer. That producer commits that volume from one of our Northeast franchises, and we can move that gas through an asset that Sequent already had contracted and deliver that to a power plant. And so those are the opportunities that we're unlocking with Sequent to where we are controlling the best we can, the volumes that are coming off our gathering assets and then connecting those to in-basin like power generation. And we continue to see opportunities there. The amount of coal-fired generation that's going to come offline over the next several years is fairly dramatic in those markets. And we're going to see that replaced with natural gas-fired power generation. And our Sequent team is out there looking for opportunities exactly like that. And that's where we can capture more market share from our gathering business where they're actually creating markets on the other end and making sure that we're connecting that from our gathering systems as opposed to others.

Any sense of what that amounts to, though?

Makes a good amount.

Yes. How much would that amount to?

About 75,000 dekatherms a day on that specific deal.

But I think our strategy up there is we don't really care what the total move out of the Appalachian is. We care about how much our is moving out of there. And so we're very focused on that, on making sure that where we have assets and capabilities, we can -- Sequent can go and contract for a pretty low margin, but if it's moving gas incrementally on our gathering systems that wouldn't have moved, that's a very high-margin business for us. And so we're very fixated on that as a team.

And I think from a gas macro perspective, it's also useful to recall, there's now, I'd say, more transparency than ever in gas macro fundamentals in the U.S. I mean coal to gas switching, elasticity has kind of left the equation. And so we saw, as an industry, I think, the rebalancing of supply and demand coming into the '22, '23, '24 period. We knew we were going to be in a bit more of a weather-dependent period. We see very clearly '25 demand coming in the form of this next kind of phase of LNG exports. And then if you look further into the second half of the decade, you see very clearly another wave of demand that's coming as well. And so I think from a longer-term perspective, there's going to have to be a call on natural gas to balance that growing demand that's coming in the later part of the decade. That will either help support projects out of the Northeast, whether we get permitting reform or projects that are going to be built along existing corridors. And that's what we see on our infrastructure. We can still build projects in the Northeast. It's just -- it's -- without permitting reform, you're not going to see large greenfield projects built across the footprint. But you will need a call on gas that we'll either have to raise gas prices to the point where basins outside of the Northeast are providing that supply or you're going to have to be able to support. And from a resource perspective, it would make the most sense to call that gas from the Northeast.

If I could, just 2 quick ones. One, Chad, do you see any need for a pure hydrogen pipeline in the future? And the second is in terms of the leg project, just on the sequestration side, how are you folks working that?

Yes. On the first answer, we believe that the best way to scale hydrogen is through leveraging existing infrastructure and through blending hydrogen with natural gas. There will be applications for pure hydrogen in the Northwest. We're looking at a market that's interested in a pure hydrogen power production solution, that's a long-term goal, where you would see an actual hydrogen market emerging for pure hydrogen. But I think about it from a real practical perspective. If hydrogen works and you could put a 10% blend in hydrogen in our Northwest pipeline, that would be more hydrogen production that exists in the world today. Just a 10% blend in Northwest pipeline. We could produce hydrogen in Wyoming, where we've been trying to produce renewable power and send it to California for 20 years. We could produce hydrogen in Wyoming, move it through our infrastructure at just a 10% blend and be the largest production of hydrogen in the world. So I actually think the opportunity is to prove out our ability to reliably move hydrogen blends in existing infrastructure. And then it will be, I think, more regional niche markets that might explore more of a pure hydrogen solution for transportation fuels for power generation. And the CCUS project question one leg. Yes. So that project, as I mentioned, the challenge with CCUS is aggregating CO2. You've got to figure out a way to get enough CO2 to justify the capital investment required to build the pure CO2 pipelines and the underground sequestration. And so we have such an extensive footprint in the Haynesville that we think we've got a good opportunity to use the existing treating, to gather, basically use our gathering systems to gather and aggregate CO2, move that into our pipeline systems, co-located with -- co-mingled with the natural gas and then extract it at a single facility and injected into underground storage in Southern Louisiana.

You might touch on whether we're going to have on that.

Yes, that will likely not be Williams owned -- I think we are very equipped to gather and transport CO2, just like we do methane but we're likely in a contract for the underground storage.

Sunil Sibal from Seaport Global. So I wanted to start off on your LNG strategy. It seems like some of the offtake agreements that you're looking at with the liquefaction plants may have a different duration versus some of your LNG marketing contracts. First of all, is that correct? And then what all steps you could take to kind of bridge that duration gap?

Sure. Yes. No, there will be some. But I would tell you that our primary focus is to be a facilitator of transactions that match as best we can term exposure across that position. So when we think about what our business will be, we think we are uniquely positioned to take on the facilitation of getting producers exposed to international buyers. And though we'll be making a 20-year commitment, there is a market for producers to take on long-term commitments that don't have enough scale or don't have the balance sheet to take out an LNG position. So if you think about a small portion of their production, yes, being exposed to a 15- or 20-year commitment. But if they think about getting exposure to international prices for a small portion of their production, we are having conversations that would match term on that downstream obligation. We'd be taking on the counterparty risk, but we think we're uniquely positioned, because we're a gatherer, we proved during, I think, the producer challenges of 2020 that we're uniquely positioned to price and get compensated for that counterparty risk that we would take on. But no, the majority of our position we intend to have back-to-back transactions that derisk the term of the exposure. And where there would be a mismatch in term, we're going to look for very adequate margin to compensate for any back-end risk that you would were. Alan, if you have anything you want to add to that?

You said that well.

Then just one follow-up on previous discussion on the gas and NGL marketing business. So it seems like over the last year or so, you've added a lot of half to that part of the business. I was curious what would take you for -- to raise that guidance on that business from $50 million to $70 million that you have guided?

Yes. I mean some of the things that we alluded to around 2023, just to touch on that maybe for a minute. I don't know that we specified this, but can give you a little bit more information on the storage position that Sequent had at the end of the year, large-scale storage position took a big -- a lower of cost or market write-down as natural gas price was falling. Well, their forecasted forward sales of that storage position are already locked in and hedged. So some of what we see in 2023 that it gives us confidence about their numbers is just the fact that their storage margin is somewhat known to us, and a lot of that is going to show up in the first quarter at '23 and it's big. Beyond that, I think what we do -- we have seen that their ability to capitalize on natural gas price volatility with their transportation positions is very powerful. And so we're not ready to take $50 million to $70 million up forever, because, honestly, some of these positions are more short term. The storage positions tend to be more shorter term in duration and some of the transportation positions are as well. So we've got to keep an eye on it. But for 2023, we feel really confident we can beat the $50 million to $70 million again for sure.

Brian Reynolds from UBS again. As for my 2 follow-ups. The first is just on the upstream business. The appendix highlights roughly half to be hedged at above $6 per MMBtu. So curious if one, could you give some color on that as a percentage versus an absolute number? And then two, could the hedging be a tailwind for any potential asset sale process?

Maybe I'll touch on that a little bit. I do think that slide is helpful. It does give our forecasted production on the upstream side. And you can see that as we go into 2023, we've talked about some of the dynamics happening with the Haynesville business, but the Wamsutter growth in the upstream relative to that $330 million of EBITDA becomes more and more important. One thing I would say about that is the Wamsutter profile -- production profile has more liquids. It has crude. It has NGLs. So it has relatively been more protected from the price drop that we've seen. Most of the hedges that you're seeing on that slide related to the upstream business now relate to the Wamsutter upstream position, because as I kind of mentioned in my commentary, as we got further and further into the sales process around -- a potential sales process around the Haynesville PDPs, we took a valuable NYMEX book that existed and shifted it over to the gathering and processing business, because we did have NYMEX exposed fees on the Barnett. So we really -- at that point, the Haynesville business is more floating and the Wamsutter business is where we've connected most of those hedges. There's some basis hedges that remain on Haynesville. But most of what you're seeing on the fixed swap, the NYMEX book is related to Wamsutter now.

And on that note, you think about Wamsutter, yes, those hedges could have value in a monetization. But for Wamsutter, what we don't want is someone to just buy the PDP cash flows even though they might be hedged in at attracted value. We want to make sure that Wamsutter's development opportunity has proven up and someone's going to come in and develop that asset. I think we're there clearly in the Haynesville, but as John mentioned, the hedges are really more focused right now on Wamsutter. So that's how we're thinking about it. But I think we're absolutely thinking about how you could lock in value and monetize that when it makes sense.

Great. And as a quick follow-up, you've discussed in detail a lot about renewable intermittency. There seems to be a strategy with M&A just around strategic natural gas storage assets coupled with the Sequent business. So just curious, one, did Sequent have exposure to the Western markets before the acquisition? And could you discuss perhaps post Mountain West and even Nortech, the exposure that you have to obviously California power markets and most recently, Opal power markets.

Yes. I'll start on. One of the great things about combining Sequent into the company and our legacy Williams marketing is that we were actually pretty strong in the Rockies, with our legacy footprint in the Rockies. In fact, the Western desk gets Sequent was really more of a Midwestern desk. And so it was really a great fit between Sequent and Williams. And so together, we're a stronger, more diverse geographic platform. And so that's been a real benefit. So we have increased our exposure to Western markets, and we're continuing to look to do that. Sequent was -- at Nortech, Sequent was, as Micheal mentioned, was a capacity holder at Nortech storage, was actually the longest term capacity holder at Nortech. So they had seen the value before the market was really appreciating, how important storage was going to be in the DFW kind of metro area. And so it's very much been a deliberate effort of leveraging that.

Yes, I would say that. I'll just add to that. The Sequent team coming in and marrying that up with our Williams Energy Resources team that was marketing gas a little bit. I mean we're marketing about a Bcf of gas every day before Sequent showed up in-house. And so they were more Western-focused, as Chad said, and we had some capacity positions to get right to that Opal market before Sequent came in, and they had that capacity in their portfolio on the [ water ] side of the house. And so married that up and we do have a more stronger focus now on the West. They have some capacity in the Socal Citygate area as well and I've taken advantage of that earlier this year or in 2022, sorry.

It's Alex Kania from Wolfe Research. Two questions. First, from Chad, you just mentioned about the visibility of gas demand, particularly with respect to LNG. If you think about what we've seen with respect to FIDs in the Gulf Coast and maybe what's likely over the next so many months, do you feel like the infrastructure and midstream is there for -- to be able to support that over the next 5 years or so, particularly with respect to your asset footprint, maybe thinking about LEG and in Sempra, the Sempra partnership? Or is there incremental opportunity there that might not be kind of fully contemplated at this point?

Yes. There is incremental opportunity. There appears to be a good amount of capacity for this 2024, 2025 wave of LNG demand coming online, but there are a lot of projects that are targeting '27, '28 and '29, and there will need to be capacity, including expansion of capacity. We think across our Transco footprint to serve those needs. And so there is quite a bit of commercial activity. Micheal can speak to you as well, commercial activity around supplied. I. think there's a lot of focus on how are we going to supply this next wave of LNG beyond the '24, '25 wave. And so we do see, and I think stay tuned, you'll see projects that are going to be developed to serve that next wave, and you'll start hearing about those, I think, in the near term.

Great. Then maybe just a quick one on tax. Previous comments, I guess, with respect to the corporate AMT was that if you thought about maybe having a higher cash tax burden near term with the benefit of maybe a longer ramp to get into a higher rate over the very long term, that the NPV was relatively small, do you still see that? And then maybe with -- in addition to that, are there any other ways via the IRA to further work to kind of mitigate your cash taxes through, I guess, a lot of these tax credits and things like that, that are moving around?

Yes, absolutely. So the answer to your first question is, yes, we still think it's a minimal NPV effect on the business. I mean an acceleration in 2024, some minimum tax that we can apply against a regular tax that was expected in 2025 shouldn't be a big value issue from our perspective. I think longer term, definitely would highlight that some of these investments, for example, the carbon capture project, the economics of a project like that might show up more in tax credits. I think you're going to see that more and more in the space. We work with tax groups across the group, the peer group, and we're hearing more and more discussion of plans for cash taxes are returning to the space. And now with the IRA and some of these investments, I do think you're going to see more capital investment for purposes of affecting tax bills. So that will be an interesting shift for the business. There's other things that I think are out there. The Section 179 phaseout of expensing capital investment, that's being phased out 20% a year. Maybe that's something that gets looked at congressionally at some point and maybe not for another couple of years. But that phase out is also affecting this, the ability to expense equipment, which is something we've had for a long time.

John Mackay from Goldman again. There's been a lot of conversation on Sequent today, and it's been a big theme in the last couple of earnings calls, too. I'm just curious, we've talked about you don't want to go up on the 50 to 70 now. But is there kind of a range on how big you'd be willing to let Sequent get? And I don't know if that says percent mix on your footprint, I don't know if that's a kind of limit on kind of self-contracting so to speak, just -- what's kind of the upside there? And how do you think about that kind of self-contracting kind of internal counterparty risk part of that?

Yes. Well, I would just say, first of all, there's a working capital constraint that we'll always impose on that. And obviously, short-term money and cash has gotten to be pretty expensive. Good for Williams because a lot of the people they compete with -- that we compete as Sequent in the market, the cost of that short-term capital has gotten much more expensive. And so it's allowing more and more margin available for us where in the past, that short-term money was super cheap for that working capital to hold gas, to hold capacity, to buy gas. So I would say that's a constraint that we impose is just a working capital constraint and as well, though in terms of growth, when we go in and buy capacity or we go in and buy a facility and own part of that capacity and expect to monetize that, the expectations for that business, just like any other asset we buy, the expectations is going to raise as we make those acquisitions. So to answer your question more succinctly, we would govern that, and we would have expectations based on the amount of working capital we allow to be put to work there, number one; two, the amount of payment obligations we're making on transportation and storage and three, any investments we're making in something like Nortechs or something like that, where we still hold some of that capacity and would expect to expand that. So those would be -- if we do put up more capital for that, we would expect to grow that business as we do that. Does that answer your question?

Dave Winans from Prudential. We're bondholders of you guys, and it's been a good ride. The balance sheet, the leverage has come down a lot. In 2020, you had a really stable, the business held together really well for a really wild year. I'm just wondering why aren't you guys rated higher by the agencies? And is there any aspiration to get higher, any advantage in doing so?

Yes. I think why aren't we rated higher -- well, you do have to look at our leverage and do account for the amount of marketing in E&P. I mean there is an element there that you need to adjust for in terms of a sustainability in the metric. I think that in order for us to be rated higher, we would -- we could definitely get to a level that would justify those ratings, but we would have to have a firm commitment to that being what we want to happen with the business. We just don't necessarily see that, that would be the best use of capital versus all the other opportunities we have in front of us today.

Michael Cusimano with Pickering back here. Alan, a quick question for you. Earlier last year, you noted the significant supply wave you saw coming, sort of in the face of the strip continuing to march higher? So obviously, your views are confirmed today, but I'm curious if you see any response now from operators or if you're surprised from the lack of response that we've seen on the supply side.

Yes. This is so highly predictable with a few variables around it, but it just always takes a little bit longer, just on the way up. It takes a little bit longer for things to build and people will get their things rolling and to have the infrastructure in place to move the gas. Same thing goes on the way down. It takes a while. People have got commitments on rigs for a few months. And so -- and they want to meet a certain requirements. So it always takes a little while on the way down for people to back that off as well. But it's a little bit different this time, is that the market is in pretty strong contango into '24 and '25 right now relative to people being going to make a pretty decent margin in the Haynesville or in the Marcellus. And so I think that's got people, particularly the private companies that tend to hedge a lot. It's got them kind of hanging on and using that contango that's in the market to continue to justify their drilling. So as long as that happens, it will happen until the back end comes down. And I think the variable that's out there that is very unique this time around is people knowing that there's a big demand pool coming from LNG and thinking about how they bridge into that. So -- and obviously, that's what's driving the contango in the market right now into '24 and '25. I think we'll -- I definitely think we will see people back up in March. Gas this morning was trading at [ EUR 210 ], so we'll certainly, I think, see some people back off. But there is a lot of people that are just looking to that forward market in '24 and '25 and saying, hey, I can make good money at [ 340 or 350 ]. So why would I not do that?

Two quick ones. One is, how do you see the cadence of CapEx going out a few years? Do you think you'll stay in this $2 billion plus or minus range? Or do you think there's opportunity to go beyond that?

Well, I think if you look at '25, a lot of the capital that we -- like, for instance, on the deepwater, we've already spent a lot of that capital has already been spent. And so we'll get a lot of growth off of that. So we've got some pretty efficient capital opportunity. I think the biggest variable right now as I think about what would drive our capital higher or lower and if I'm looking at the 3-year kind of horizon, is going to be very dependent on whether or not MVP gets built or not. If MVP doesn't get built, then there's going to be a lot of demand for the services that we can offer down our right of way, we're going to make some really high margin, less capital but higher margin business if MVP gets built, because then we've got the margin in those small increments of capacity expansion. And as Micheal explained, we can charge whatever the market will bear on that. And so those would be lower capital, higher return versus if MVP doesn't get built, we'll have bigger capital with lower return in that space. So I think that's what will probably drive for us, that's likely what's going to be one of the biggest drivers of capital for us.

Just a point of clarification, right of way is a big asset for you. But are you allowed to do looping within the right of way? Or do you have to file for permits to do the looping?

Well, yes, you'd have to file for permits for an expansion. But if you were picking up -- we have a lot of our pipeline that we've derated over time, because of class location. So you've had population infringement in and around the area. And when that happens, you have to lower the pressure that your MAOP on the pipeline, and therefore, the pressure you can operate. Nothing stops you from being able to restore that through maintenance activities, which would not require that kind of permitting. And there lies for a lot of the big opportunities for us.

And my last one is the question on valuation. At what point in time do you think folks start focusing on EPS as the valuation metric as opposed to just focusing on EBITDA?

Yes. I mean, I think we're getting to that. I think one of the things that we're quietly excited about because it's -- I think you'd want to necessarily brag about, but our EPS is up above our dividend now for the first time in a long time. And so we're excited about that. And so I think EPS should be an important thing for people to focus on over the long haul. And I think the challenges to it are the noncash taxes and it obviously is a big issue, and the depreciation is so typically so out of balance with the life of the assets. I know the accountants don't like to hear that, but that's the truth. And so we tend to have depreciation cycles that depreciate the assets very differently than the useful life of the asset. So both of those make EPS a little bit strange in the midstream space for those reasons. But I mean, if I'm an investor, I certainly pay attention to EPS at companies, knowing that there are some liabilities that they're wearing, whether it's noncash taxes or a long-term depreciation. One thing I haven't mentioned, though, that I think is -- I don't know how our timing could be any better than it is right now relative to depreciation and cost of capital is as we go into our rate case right now on Transco, I give you to give me a book and said, okay, you get to pick a scenario that you'll be going into for your rate case, you couldn't have picked a better scenario than we have right now. Debt costs coming way up, cost of capital coming up, obviously, with that, inflationary pressures on operating costs right now that may subside over time. So it's a really pretty perfect environment to be going into our rate case on Transco.

Jeremy Tonet, JPMorgan. Just looking at Slide 103 new energy ventures. You list a number of things on the slide there. I guess that's on your plate right now. And just kind of thinking longer term, what are you guys most excited about here? Besides next-gen gas, hydrogen, CCS, RNG, corporate venture capital. So which one of those investments could have the most meaningful impact on Williams, say, 10 years down the road?

Go ahead, Chad.

10 years down the road -- I get excited about all of them, but I would tell you that we're also pragmatic, can be natural gas. I think our next-gen gas program, I mean, hopefully, you've heard it like -- if you really care about our environment, if you really care about rising people out of poverty around the world, I mean natural gas is the most powerful tool that we have and so I think by demonstrating with credibility, that story with next-gen gas being able to show from wellhead all the way through burner tip, the ability to drive down global emissions, that's why we're so focused on next-gen gas. I mean it is, we think, the tool that can have the greatest impact on our world over the next 10 years. When you look further out, I wonder, I mean, I wonder if that bottle of water is the most efficient energy source for powering a power plant. I mean if it is, we're going to figure out how to make sure that our infrastructure delivers it to power plants across the country. The scale of that opportunity is massive, but it is really hard to turn a glass of water into a fuel for a power plant. So it's very expensive. And so we're being very pragmatic about the opportunity. But if that works, then I think we will certainly be there. I think that CCUS is very interesting. It's hard to aggregate CO2. That's what we've talked about. You need a lot of volume aggregated to justify large capital investments. So that's what you're seeing happening in the space is how can we go out and find large enough emission sources. So I think we're excited about the fact that we know infrastructure is irreplaceable, and it's going to be necessary. I talk a lot about it. We're not going to tear out the highways and build a new highway system, because we're electrifying vehicles. We are not going to be able to build a new energy ecosystem for the United States and get rid of all of the pipeline infrastructure. We're going to have to take advantage of it. So I think that's how we think about the opportunities and kind of what gets us the most excited.

We've got one last question for the team.

Kind of finish things off on valuation again. If you don't get credit for a long-term sustainable 6% plus-ish EBITDA CAGR apart from share buybacks, apart from monetizing your upstream, which eventually you'll do. Is there anything more fundamental, strategic that could be done to unlock shareholder value? You've been very good on the acquisition front, buying at mid- to high single digits and then integrating for higher value add. You've been very good on the sale side, sell side with 13-plus multiples. You're talking years ago about when you need a balance sheet repair about monetizing a portion of your West segment. If there's a systemic problem with the market just not believing in the 6% base CAGR, which sounds like there's upside to that potential. But if the market just doesn't believe it, doesn't give you credit, and we're a couple of years down the road, what major levers can you pull?

Well, if you just look at the free cash flow that we'll continue to generate in that environment. If you think about the last several years, we've been taking down, we've been taking down debt. And I would say if we're not seeing that, certainly, I think you'd see leaning more into share buybacks as a value proposition if we see that. But I don't really think that will happen. I think we'll continue to have the growth. And I think that the EPS growth that we have is going to be really hard to dispute the way we think it's going to continue to grow. We think it's going to be pretty hard to dispute the value proposition that exists there over the long haul. So yes, I'm as impatient as so as that you would find. But -- and so this is -- it's hard for me to sit and wait for that. But I do think we're creating tremendous value. We continue to produce a nice dividend for our shareholders and a growing dividend for our shareholders. And I don't see any reason -- I don't see us investing in anything that I don't think is creating long-term value for our shareholders. And when that gets realized, there's not something I can predict all that well, but it is creating value. And I think that's what we have to continue to work on. Our ROCE is continuing to go up, our EPS, obviously, is growing rapidly, and eventually, that's turning into shareholder value. In the meantime, we get a pretty attractive dividend and a growing dividend in the meantime. Okay. All right. Great. I have a closing remarks, so don't -- this is where everybody already starts getting up and walking out. So it's really good stuff. So I'll hang time for just a second here. So I just want to close here with -- we covered a lot of materials today, certainly, and I really appreciate your patience and your interest in the company. A lot of you all have been around the company, know the story well, and I'm very thankful for your engagement and following the company. So I want to say that to start with. But we certainly are the most natural gas-centric large midstream company. And there's a reason that we've -- with our natural gas focused strategy have stuck with it for as long as we have. So this isn't anything new. We've stuck with it. But not only is this strategy delivering in the current environment, but the signals coming from the market show that it is going to continue to deliver substantial growth for the long term as well. We do expect strong fundamentals to drive attractive growth opportunities for Williams. You heard about a lot of those today including the higher demand for U.S. LNG exports and a faster pace of coal to gas conversion with the lion's share of these projects residing along the Transco corridor. So growth in electrification, as we talked about, will drive higher demand for gas transmission and storage capacity going forward. Natural gas demand across all the various sectors continues to increase in the face of higher natural gas prices. I think that was pretty impressive to see the way this summer, I would have expected for demand to back off when we had high prices this last year on gas, it did not and I think that's very encouraging to see how -- in elastic. But I do think long term, I think gas, we've got to be able to really be a big exporter of gas, we've got to be able to take advantage of our low cost of development here in the U.S. And I would just say it is -- I think when you really study this, I spent a lot of time trying to find somebody that can tell me what we're wrong about on our natural gas strategy. And you just keep running your head into the same old issues over and over and over. And really natural gas is the solution for, I think, the most complex challenge really that our civilization has today and on one hand, producing low-cost energy resources that keeps our world peaceful on the one hand -- and on the other hand, being able to reduce emissions around the world, that is not a small problem. It's a huge problem. And natural gas is the most powerful tool by far that we have right here right now. And I think the more times we veer off and try this and try that and kind of ignore that, the more pressure it's going to put on the value of natural gas longer term, because it really is that only alternative. So the -- we do have abundant resources here in the U.S., no other countries as well positioned as we are and the infrastructure that we have here in the U.S. is going to continue be incredibly valuable. And I think we really sometimes misunderstand the value of the existing infrastructure and the existing right of ways and the kind of margin and value we can create for shareholders by going after these higher-return projects. So I just want to say we're very excited about the way we're positioned today. We don't really see -- it's really hard to come up with a scenario in this environment where we don't have a very attractive growth path going forward for us and one that's extremely durable, whether it is continued high interest rates which, frankly, I think is going to continue for some time. I don't think that J. Powell has any desire, whether we may all want him to, I don't think he has any desire at all to back off until 2% inflation is reached. And I think that's a long and difficult road and I think businesses like Williams that are going to be extremely durable in the face of that is exactly where investors ought to be looking for, for value right now. So I appreciate all of you all's interest in the company. We look forward to continuing to deliver value for our shareholders, and we very much appreciate your interest. Thank you for being here today.