Danilo Juvane:

Thanks, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call today are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important integral to our remarks, and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. And these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

John Porter:

Thanks, Alan. Starting here on Slide 3 with a summary of our year-over-year financial performance, beginning with adjusted EBITDA, we saw about a 3.5% year-over-year increase, despite low natural gas prices that fell about 5% versus 2Q '23, averaging close to -- for second quarter of 2024. And that 3.5% adjusted EBITDA growth is over a second quarter last year that had grown about 8%. So in spite of low natural gas prices, once again, our resilient business continued to grow even [indiscernible] customers employed pretty significant temporary production reduction measures like not completing drilled wells and/or not turning in-line wells that now stand ready to flow as prices improve. As we'll see on the next slide, our adjusted EBITDA growth was driven by strong growth from our large-scale natural gas transmission and storage businesses, including the favorable effects of our recent acquisitions. Year-to-date, our adjusted EBITDA is now up 6%, so inline in the middle of our long-term growth target of 5% to 7%. For Q2, our adjusted EPS was up 2% and year-to-date EPS is up about 3%. So a bit slower EPS growth in '24 as compared to the 19% 5-year CAGR that we've seen through 2023. But as Alan mentioned, looking through '25, we do see a 5-year CAGR that will be in excess of 12%. For 2Q, available funds from operations, AFFO growth was 3% and 4% year-to-date. Similar story here with this slower '24 growth is following an 8% 5-year CAGR through 2023. And when you look through 2025, we see a 5-year CAGR of 7%. Also, you see our 2Q dividend coverage based on AFFO was a very strong 2.16 on a dividend that grew 6.1% over the prior year and 2.38x coverage year-to-date. And our debt to adjusted EBITDA was 3.76x, which is in line with our expectations, slightly higher leverage in 2024 before dropping back down in 2025 to guidance of 3.6x or better. So before we move to the next slide and dig a little deeper into our adjusted EBITDA growth for the quarter, we'll provide an update to our financial guidance. In general, our second quarter update is unchanged from what we provided in our first quarter earnings presentation. Based on our strong start to '24, we guided to the upper half of our 2024 adjusted EBITDA range of $6.95 billion to $7.1 billion, and we indicated that we were well positioned for upside to drive toward the high end of this original guidance. We also shared that we remain well positioned to deliver on our 2025 adjusted EBITDA range of $7.2 billion to $7.6 billion. And that based on our improved '24 adjusted EBITDA outlook and some other changes, we saw our key per share metrics, adjusted EPS and AFFO per share coming in at the high end of their ranges for 2024. So again, no major shift to that first quarter update, except perhaps to say that we are increasingly comfortable that we can clear the $7 billion level for 2024 adjusted EBITDA while still not counting on any additional help from Sequent. And of course, we also wouldn't include the around $150 million gain we expect to have on Aux Sable sale in there as well as we exclude gains and losses on asset sales from our adjusted EBITDA measure. So let's turn to the next slide and take a little closer look at our first quarter results. Walking now from last year's $1.611 billion to this year's $1.667 billion. We start with our transmission and Gulf of Mexico business, which improved $64 million or just over 8.5% due to the combined effects of a full quarter contribution from the Hartree Golf storage acquisition, which is delivering as expected, following a flawless integration effort. We also had higher Transco revenues, including partial in-service from the Regional Energy Access project, and segment growth was unfavorably impacted by last year's Bayou ethane divestiture and also some planned downtime in the Eastern North of Mexico. Now the $36 million unfavorable variance for the Northeast G&P business is really against a strong quarter last year that included the effect of a onetime $15 million favorable gathering revenue catch-up adjustment. However, we did see lower Northeast gathering volumes that were driven by those temporary producer reductions that were basically roughly in line with our plan for the year. And partially, those volume reductions were partially offset by rate escalations across several franchises in the Northeast. Shifting now to the West, which increased about $7 million, benefiting from the DJ transactions that we completed in the fourth quarter of 2023. The increase in the DJ Basin results was about the same magnitude as the unfavorable loss of hedge gains we had in 2023. Segment performance was also favorably impacted by higher NGL service results, including Highland Overland Pass pipeline volumes where low natural gas prices have supported greater ethane recoveries. Overall, West gathering volumes were also lower as a result of temporary producer reductions primarily in the dry gas Haynesville area. And then you see the $2 million lower marketing loss that was in line with our plan based on the expectation that our natural gas marketing will typically have a loss in the second quarter. Our upstream joint venture operations included in our other segments were up about $2 million from last year. So again, a second quarter that continued to beat our business plan, proving once again our ability to grow our business in spite of a challenging natural gas pricing environment and also giving us further confidence in our ability to beat $7 billion of adjusted EBITDA in 2024. And with that, I'll turn it back to Alan.

Operator:

[Operator Instructions] Our first question comes from the line of Praneeth Satish of Wells Fargo.

Alan Armstrong:

Yes. Well, first of all, Praneeth, thank you for the question and important issue. First of all, on actually, our return is even better than that, probably, as we've mentioned, the best return we've ever seen on a large-scale project on Transco and actually any of our transmission expansions over the long history for Williams. So pretty extraordinary return opportunity there. In terms of the data center load, we are right in the throes of that. We have a very long backlog of projects. And I will tell you that particularly in the Southeast and Atlantic, those expansion opportunities that we have, we frankly are kind of overwhelmed with the number of requests that we're doing and we are trying to make sense of those projects. Obviously, we're not going to start or announce another expansion project on the top of because obviously, that would force a combination of projects. And so it doesn't make any sense for us to be making any announcements when we've got a large project that we've committed to our customers to do everything we can to get that permitted cleanly and push that ahead. So extremely critical expansion for our utility customers in the Mid-Atlantic and the Southeast, and we understand that. And we're going to make sure that we deliver on that first to our customers. But despite the fact that there's a lot of attention there in the Southeast and the Mid-Atlantic, we're actually seeing strong demand response, a lot of projects that we're dealing with and trying to figure out how we can respond to in the Rocky Mountain states, particularly in Eastern Washington, the Quince area, in Idaho, in Salt Lake City region. So a lot of demand going on everywhere. And frankly, the big developers that we're working with are looking to find where they can -- because the time is of the essence, probably more than we can even imagine in our business. And so they are looking to where the permitting regime is right, where there's access to abundant natural gas supplies and frankly, where expansions on our systems are available. And so -- this has moved from being one of where people have been very focused previously in cloud-based data centers. They've been very focused on the latency issue or in other words, the connection into the -- into very fast and broadband networks to where they are now focused on the latency being less of an issue, not -- I wouldn't say it's not an issue, but less of an issue and the speed to market for power generation and gas resources being available to power that are coming front and center, along with the local air permitting issues associated with that. So I would just tell you, it is kind of an exciting time for us and even for me personally to be in such a steep learning curve on how we are going to make the very best use of our assets, but there certainly is not a dearth opportunity for us in that regard. In fact, as I said, it's a little bit overwhelming, and we're going to have to just make sure we make the very highest use of our assets because there obviously is as we expand the lower-cost expansions drive very high returns, but we only have so many of those. And those are precious, and we know that -- and so we're making sure that we make the various high return associated with the expansion around our assets. So we're not going to put a number on it because I hear people putting a number on it. And frankly, that's a very large guess. And in a time frame frankly, that's out there so far that -- and if you're not speaking to the returns that you're making on the project, I'm not really the purpose of quoting those kind of numbers when you're not really talking about the economic or financial impact to your business, and we're not ready to lay that out. But I can tell you that if anybody else has more opportunity than we do, I wish them luck because we're going to have a hard time keeping up with the opportunity in front of us right now. So hopefully, that gives you some color, but I would tell you, I think it's not all that meaningful to quote volumes on expansions if you're not talking about returns and you're not talking about the time frame for those opportunities.

Alan Armstrong:

Yes. Well, first of all, yes, gas is up and flowing, and kudos to our team for being able to respond so quickly to that. Just incredible project execution on that project in a difficult area. And I'm going to turn it to Lane Wilson, our General Counsel, to speak to the label proceeding.

Operator:

Our next question comes from the line of Jeremy Tonet of JPMorgan.

Micheal Dunn:

Jeremy, it's Micheal. Yes, I think right now, we feel good about where we're at in regard to our current forecast for the production profiles coming from our customers. You've got to look at it between the rich basins and the dry gas. And obviously, the dry gas is challenged by pricing now. So producers are making a month of decision on gas volumes that they might shut in. I think you probably saw Cutera's announcement where they were shutting in $300 million for the month of August. And it's really a month-by-month decision for all the producers out there. But right now, we've anticipated this, as you've probably seen through the first half of the year. The team did a really good job anticipating where the production shut-ins would occur and the delayed tills and ducts. I would say right now, we've got over a Bcf of delayed TILs in the queue right now between all of our customer base, meaning that the producers have drilled the wells and completed them, and we've connected to them, and are ready to go when the price signals are there. And there's over 1 Bcf as well of us, so they've been drilled but not completed on our systems. So there's definitely a lot of opportunity to bring on gas as a producer, we see a price signal. And so I'd say our risk basins are still outperforming. We're seeing good pricing netbacks for the producers there, and that certainly buffers the dry gas situation that we have right now. But all in all, we feel good about our end-of-year forecast. And certainly, 2025 is going to be presentative as well. The Golden Pass LNG facility, you probably saw the announcement yesterday that they're going to be an end of 2025 in service, it appears. And so that should have been anticipated already by the market. It looks like with the forward curve. And producers will be making decisions on these curves. And when prices elevate, obviously, they'll hedge into that and keep their volumes flowing is what we anticipate. So we're really comfortable with where our current forecasts are.

Chad Zamarin:

Yes. We've responded to the FERC data request, and we fully anticipate that FERC is either going to dismissed this matter or find a LEG as a gathering system. We don't -- really don't have any concerns there. And so there's really nothing for us to do right now except to continue down the current road, which is in construction. Again, we feel pretty confident about where we are in this project.

Spiro Dounis:

Alan, I want to go back on your closing comments there and maybe if we could tie power generation demand with how you're thinking about the EBITDA outlook longer term. So one of your slides, Slide 17 points to 10x the amount of electricity demand grow over the next 10 years versus the last 10 years. I think you mentioned in your comments there, you guys have been able to grow at about an 8% CAGR historically. So as you think about the go forward here, you guys have that 5% to 7% growth target out there. Is it sort get about that as maybe potentially moving higher in this environment, which I don't think you contemplated when you sort of laid that out there.

Spiro Dounis:

Great. That's helpful color. Second question, just going to M&A. Was hoping for an update on the landscape. And if you're seeing the same value proposition you saw over the last 2 years or maybe if we could expect you to look a little bit more inward now and consolidate some of these other JV positions?

Operator:

Our next question comes from the line of Manav Gupta of UBS.

Chad Zamarin:

Yes. This is Chad Zamarin. I'd say, again, we owned 60% of the Discovery joint venture with Phillips 66, and they've been a great partner for us. But -- you've heard a lot about our offshore growth. And so it's certainly a core part of our business and a very attractive growth profile ahead. And so we very core for us, I think you'd probably hear not core for PSX. So as Alan mentioned, where we have joint venture interests, we understand the operations of those facilities. It's a low-risk investment for us. We see growth coming. In this quarter, if you think about Discovery, we were able to acquire that at what we think is a low multiple on a go-forward basis, as you'll see the growth in Discovery really ramp up remainder of this year and even more impressively into 2025 and beyond. And are stable on the other hand, again, an asset that we've owned for a had a great relationship there, but not core to our business, and Pembina has been consolidating their ownership in Aux Sable and the Alliance pipeline system. And so we're able to sell that we saw pretty high mobile and. And you think about the difference in those cash flows, Aux Sable is a more volatile commodity-exposed set of cash flows discovery contracted asset that's going to grow. So I don't think that, that should be translated to other assets that PSX may own. It really is us, I think, rotating and optimizing our portfolio in a way that's going to create incremental value. And that's really the strategy when we look at any transaction, where do we have a unique opportunity to turn something into more value by owning or consolidating that interest.

Chad Zamarin:

Sure. Yes, this is Chad again. We've only owned the Hartery storage assets for just 6, 7 months, and we've already seen really attractive recontracting of storage at rates that have exceeded our expectations. We have been in the test whether or not we're seeing those rates and the tenor of terms approach expansion economics. We've seen the storage market certainly growing in value. That's why we acquired Nordex, the Gulf Coast storage. We acquired Clay Basin in the largest storage asset in the Rockies as part of the MountainWest acquisition. And in all cases, we've seen an increase in value in storage over the last few years. I'd say that we're still climbing the curve towards what we think makes sense from an expansion perspective are, I think, approaching the rates that are required for both brownfield and potentially greenfield expansion, but we're still needing to see a bit more depth in erosion rates for us to put large capital to work in expanding those facilities. But all signs are -- we've shaped the fundamentals. We haven't grown stores as a country at all over the last 10 years, while gas demand has been and will continue to grow significantly and importantly, we'll grow in more volatile markets. And so we have a lot of confidence that storage will continue to increase in value and we will, at some point, reach the point at which expansions it makes a lot of sense.

Neal Dingmann:

And my first question, just on the gum, especially. Could you talk about the continued upside there. Specifically, it's interesting. It seems like you have a lot of opportunities for additional projects. I mean, I think you all mentioned the 2 to 0 CapEx tiebacks that you announced after in that acreage dedication. So I'm just wondering sort of not even for the remainder of this year, but in '25, how are you sort of looking at upside potential there?

Neal Dingmann:

Fantastic details. And then just one quick one on West. Specifically, you've been -- there's been quite a bit going on in the DJ with -- around the acquisitions there. I'm just wondering can you talk about potential near-term upside around what you see for those acquisitions?

Neal Dingmann:

Yes.

Chad Zamarin:

Yes. I would say that area continues to perform and, frankly, outperform. We really like the positioning that we have. We've got not only are we seeing more integration value in being able to optimize processing and gathering in basin. But because we market and transport the NGLs, we see a lot of margin from that growth further downstream. And so -- yes, I think you're already seeing some of the important contributions, and we do expect that to continue to grow for a long time to come. So we expect our performance

Zack Van Everen:

Just shifting to the Northeast. You mentioned rates on the Susquehanna and Bradford ticked up this quarter. I know you have cost of service contracts, at least on the Bradford side. Was that part of dynamic? Or was this something else? And is this kind of a good run rate going forward? Or is this kind of a onetime revenue makeup like we saw last year?

Alan Armstrong:

Probably the main thing that you see in the numbers you're looking at a the fact that when we see more and more activity in the rich gas like we've been seeing, you see our margins in the rich gas are almost double what they are in the sometimes more than that. And so as the drilling moves into some of these rich gas developments like in the Utica and in Southwestern PA and West Virginia, you will see our average rate increase as the more and more of the mix moves into the rich gas. In addition to that, though, we have the inflation adjuster that hits every spring as well. And so that picks up those rates as well. So a lot of positive momentum on rates. And importantly, as we've said in the past, when the dry gas area is challenged, typically, we see the rich gas respond, and we make somewhat higher margin on the rich guest because of all the services we provide on it that tends to offset declines in the dry gas.

Alan Armstrong:

Chad, do you want to take that?

Operator:

Our next question comes from the line of Robert Catellier of CIBC Capital Markets.

Micheal Dunn:

Yes. Thanks for the question. Yes, we would love to see a settlement there. We'll obviously get our rate case filed at the end of the month and then work on seeing if we can get to a settlement. We've obviously been talking to the customers for quite some time about the modernization efforts that we have underway. And there should be no surprise to them when we make our filing and they see the amount of investment that we've made there. And so we do think that will help possibly grease the skids for some type of modernization tracker with them so that we could smooth out some of these increases going forward on the Transco assets, just like we've done on the Northwest pipeline. Rates with our last rate case that we settled there. So that is the intent going in as hopefully, we can get a modernization tracker, not just for our emissions reduction program, but for some of our pipe replacements that are needed some of the growing population centers there. We have a significant amount of pipe that we derated over the last several years and decades that we could upgrade and we will be doing that, but it would be better to do that through a modernization tracker as well. So that is the intent. But we've had a pretty good opportunity to discuss and alert the customers as to what to expect in this rate case. And once we get it filed, we'll start the settlement opportunities. But -- as you probably well know, the rates will go into effect on March 1 of next year, subject to refund once we either get a settlement or fully mitigate the outcome on the rate case.

Alan Armstrong:

Lane, do you want to take that?

Robert Catellier:

Yes. I'm just wondering if that decision changes how you approach future permitting activities?

Operator:

Our next question comes from the line of Tristan Richardson of Scotiabank.

Alan Armstrong:

Tristan, thanks for the question. And the reason this is important is because that CenterPoint has been plagued with a number of very high price spikes in the Texas intrastate market for various reasons. And this allows them access to gas supplies that are more associated with the Henry Hub from a pricing point and gives them reliable access to supplies from Louisiana without being dependent on the volatility that some of the Texas intrastate pipes and markets have imposed on them, both for power generation and for normal residential loads. So we think it's a great project for CenterPoint and important for us, really, all we need to do there is primarily just an interconnect and that will allow for us to provide gas supplies coming into the Louisiana market, places like Giles, which is becoming obviously an important pooling point for supplies. And this will allow them access to those supply points from places like the Haynesville and diversifies their supply and again, kind of moves them away through volatility. So for us, it's a great project because it's effectively. We're getting paid for transportation capacity flowing back to Texas and requires variable capital on our part, mostly just the interconnect there. So -- exciting and I think a meaningful improvement for Texas and the volatility they've had to deal with there from some of the suppliers into that market. And -- but in terms of -- this is just basically transmission quality gas coming out of Giles that will help supply directly to their markets there down the Transco corridor. So pretty simple on one hand, but pretty important on the other.

Alan Armstrong:

Yes. It's a great question. I think the primary issue with the permitting, it's not really the FERC. FERC, I think, has been very responsible agency, particularly under Chairman Philips leadership. And I think they're trying to do the very best to see responsible infrastructure get developed, and they realize it's very clear to them the kind of challenges that we're going to have on the grid if we don't have natural gas supplies available to provide incremental power supplies on the one hand and backing up renewables on the other. That is not lost on them at all. They face that responsibility as a commission and an agency, and I think they take it So that's not really where the problem. The problem really revolves around the NEPA process and the handles that it gives to environmental opposition to take up issues that have very little to do with the pipeline construction, but have to do with their own fight against fossil fuels. And because the NEPA process allows them to kind of grab hold of projects and appropriately the NEPA reform is probably the most important thing and really excited everybody has been talking about the Chevron deference, which we think is important, but you also saw the Supreme Court agreed to take up a review of the NEPA process as well. And I'm actually really excited to see that. That could really reform permitting in a way that's meaningful and really stop people from being able to just arbitrarily stop projects and they're tracking cause lawsuits in the process, which is the NEPA process that we know today. And so anyway, that's important to the 401 water quality certificate that the states are allowed that gives them a right to just stop projects is important to see that turned around and as well as the judicial standard for the way that a court would review a complaint against the permit. So those are really the 3 primary things that we're looking for. And I actually were pretty normally not very optimistic about seeing anything happening on the permitting reform, but really excited to see the Supreme Court taking on the NEPA review. So we could see some. It's not going to be quick, but we could see some relief there down the road.

Theresa Chen:

Based on what we've seen in the market very recently as far as the data center related or data center-driven brownfield expansion on natural gas transmission. The implied rates seem to be far above several multiples of existing tariffs and economics. Is that consistent with your expectations as you move through the process of addressing the sheer number of requests you have? And is that a key hurdle in getting these projects done in addition to speed to market?

Theresa Chen:

Got it. And a follow-up on the regulatory front. As we approach the election season in the fall, what are your latest thoughts around that as it pertains to assets within your business? Any key considerations on your mind as we move through the next few months on this front?

Operator:

Our next question comes from the line of John Mackay of Goldman Sachs.

Alan Armstrong:

Yes. Well, John, thanks for the question. I would just say that what we're seeing is a shift because I think that the developers are realizing that they're kind of up against a brick wall right now in terms of extracting more generation off the grid. They realize that that's pretty well exited. And so they're going to look to areas where both natural gas resource is available. The capacity for it is available and as well as the permitting allows them to go build out some very significant power generation behind the meter on the one hand. We still are seeing a lot of growth on the utilities as well, more for the conventional data centers and the cloud-based data centers, a lot of growth continuing as well as just general electrification of load. Sorry, that is driving that as well. But in terms of the hyperscaler and their approach right now, we are seeing them look all the way back into areas where the gas resource is abundant and the permitting allows for getting on with developing the infrastructure that they need to have reliable and affordable power into those markets. But as Micheal -- I think the -- in my earlier comments, the speed to market seems to be the thing that is most top of mind for the big, big hyperscaler developers. And so that's where we think there's going to be opportunity in places like Wyoming where we have a lot of gas resource available and a lot of wind resource available as well. And so I think we're going to see that. But we're also going to get a lot of indirect load from our utilities in these other areas as both the conventional data centers and electrification continues to grow in those markets.

Alan Armstrong:

Yes. Well, I would just say, if you think about all of the supply that the Haynesville has available and some of the resources even south of Haynesville that we think will get developed in a pricing environment that's coming forward right now. We think that having access to those Louisiana supplies the diversity of supply, is really important. Again, as I've mentioned in my comments, if you think about the pain that has been inflicted on some of the Texas utilities from the Texas intrastate market where they didn't have us to a more diverse supply. We think this is a trend. I mean, it only makes sense that they're going to look to see what's been imposed on them from a pricing standpoint and look for more liable loss supplies to be available. And to me, that's the important thing about this is then recognizing that, that fluctuation did not occur in places like Louisiana and really only incurred on the Texas intrastate markets, and this gives them access to a more diverse supply. So that is the keynote to take away from that project.

Alan Armstrong:

Okay. Well, thank you all very much for joining us today. An exciting time for us here at Williams as we continue to deliver the long list of projects that we have in execution and that continues to mount growth for us. and importantly, how strong the future is in terms of the demand that we are excited that we have an opportunity to help address, but an exciting challenge for the organization that we're excited to show what we're made of on that front. So with that, thank you very much for joining us today.

Danilo Juvane:

Thanks, Andrea, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we released our earnings and press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, who will speak to this morning. Also joining us on the call are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development.

Alan Armstrong:

Okay. Well, thanks, Danilo, and thank you all for joining us today. Well, another first quarter and another strong start for Williams. So let me begin here on Slide 2 by calling out a few operational financial and strategic achievements we saw this first quarter. Starting here on the left of this slide, Yet again, we've set a record for contracted transmission capacity led by Transco, the largest and fastest-growing natural gas pipeline. And in January, we closed on our acquisition of a portfolio of Natural Gas Storage assets from an affiliate of Hartree partners for approximately $1.9 billion. The transaction included 6 underground natural gas storage facilities located in Louisiana and Mississippi, making us the largest owner of storage on the Gulf Coast.

John Porter:

All right. Thanks, Alan. Starting here on Slide 3 with a summary of our year-over-year financial performance. Beginning with adjusted EBITDA, we saw an 8% year-over-year increase despite natural gas prices that averaged less than $2 for the first quarter of 2024. Now included in that 8% overall growth is almost 13% growth from our primarily fee-based infrastructure businesses, excluding marketing and the upstream JV. As we'll see on the next slide, our adjusted EBITDA growth was driven by strong growth from our core large-scale Natural Gas Transmission, Gathering and Processing and Storage businesses, including the expected favorable effects of our recent acquisitions. And it also included strong performance from our Sequent Marketing business, which had another strong start to the year despite falling a bit short of the extraordinary start they had to 2023.

Spiro Dounis:

First one, maybe to start with the guidance, two-part question there. So John, you'd mentioned leaving room for some volume reductions from here. Curious if you could provide a little more detail there and how to think about maybe the cadence as we go throughout '24? And just given that you've left '25 EBITDA unchanged. Sounds like maybe '25 also contemplates some slower activity levels. So just curious to kind of get some confirmation around that?

Micheal Dunn:

Yes. This is Micheal. I can add to that. Obviously, we talk to our producer customers quite often about their plans and they're shifting, obviously, back and forth, depending on where prices are. We feel really comfortable where we've had predicted our results to occur in the second half of the year here with our guidance -- confident. Based on the volume expectations that we have coming from the customers. And so just as a reminder, and I always say this, we have a lot of diversity across geography, customers and rich gas as well as dry gas. And obviously, that benefits us and having that diversity and so we're still seeing some activity on the rich gas side, it's benefiting not only our gathering but our processing business in the Northeast. And as I said, we feel confident about the volumes that we have embedded within our going-forward plans here in 2024.

Alan Armstrong:

Yes. Great question, Spiro. And I do think that this is one that will grow over time. Each individual data center isn't going to show up as a big pool and demand given the size and scale of most of these big transmission systems. So it is going to be the collective amount of data centers in these markets that's going to show up. But there certainly is a lot of fury going on right now, I would say, both with our utility customers. And we certainly are working closely with them to make sure that we can serve their needs and the growth in their needs. I would tell you that it's broader than even though data centers and AI gets all the hype, it's actually broader than that in terms of a lot of reshoring of industrial loads that is occurring as well. And part of that is because natural gas is so low cost here. If you think about the rest of the world and the energy cost expanding in the rest of the world and the U.S. sitting here on such a great resource of low-cost energy, it is reshoring industrial loads as well.

Operator:

Our next question comes from Jeremy Tonet with JPMorgan.

Alan Armstrong:

Yes. Great question, Jeremy. I firmly agree with the notion that the market is oversupplied right now. And it's kind of a unique time because we've had the market in such strong contango here for quite some period. Putting a lot of value on our Storage. I would tell you we feel very fortunate to have bought the storage that we bought in the time frame that we bought and to pick up the contracts that Sequent had on storage as well. So a lot of in the money business around the storage business because of the strong contango. But that strong contango is also keeping rigs running that might not otherwise be running right now. And I think that's adding to the oversupply situation. But we certainly are starting to see producers respond to that. And we're also starting to see the demand side respond to that as well. And I think we'll see more of that this summer, and the market always finds a way to balance itself with low enough prices.

Jeremy Tonet:

Got it. And then I just want to pivot over to LEG and I was wondering if you could provide any updates on project progress at this point given litigation other items in play? And any thoughts, I guess, on Basins in Southern Louisiana just given there seems to be a concern that, that could widen out without the infrastructure coming into service?

Operator:

Our next question comes from Manav Gupta with UBS.

John Porter:

Yes, absolutely. So when we look at 2025, we've got really quite a bit of spend expected on the Louisiana Energy Gateway project that Micheal just referred to. So that would be in the category of gathering and processing expansions. And by far, the biggest in the gathering and processing area would be the Louisiana Energy Gateway pipeline project. We do have some new Energy Ventures investments that we're expecting to begin to spend some money on, including our first Carbon Capture and Sequestration project, which is at the terminus of the Louisiana Energy Gateway project. So it's related to that LEG project. But we also have some solar projects that we'll be investing in.

Alan Armstrong:

And Gupta, I would just add in terms of drivers for growth in '25. We have a number of large deepwater projects that we've already spent a majority of the capital, those will be coming on towards the end of this year and into next year. So we're really excited about the big step-up in deepwater growth and how well we're positioned out there for what we think is going to be a lot of continued growth in that area. So -- but in terms of drivers for growth, that's one additionally, drivers for growth would be the rate case on Transco. And so the benefit of all the money we're spending right now on the emission reduction projects will show up. The benefits of that will show up when we start charging our new rates in March of '25. So those are some of the other drivers for growth.

Operator:

Our next question comes from Praneeth Satish with Wells Fargo.

Alan Armstrong:

Yes. Good question. Yes, the first evidence of that, even though it really was before the data center load became quite so evident, is our Southeast supply enhancement project. We've announced that and now filed it in the first quarter for 1.6 Bcf a day, and that does serve both the Mid-Atlantic and the Southeast markets. Since that time, as I mentioned, those utilities have come out and said that they were missing their growth targets by many multiples. In fact, I think Southern companies came out and said they missed their original growth for power generation by 17 times. So lots going on in those markets. In terms of our abilities to serve those, we're extremely well positioned to serve that.

Praneeth Satish:

Got it. That's helpful. And then I just had a couple of questions here on the Washington Storage Transition to market-based on Transco. Can you just help frame maybe how much of an uplift you expect for moving that from -- to market base from, I guess, cost of service? How much difference in rates could you see there? And then how much of that capacity do you need to go through an open season now? And how much of that capacity do you think third parties could take versus Sequent? And then finally, is this shift to market-based rates and the upside is that reflected in 2025 EBITDA guidance at all?

Micheal Dunn:

Yes, I'll take that. So yes, to answer your last question first, that is embedded in our guidance for 2025. So the process where it stands now. FERC has approved our settlement with the customers, the customers have a choice to take a tranche of capacity on a term that they so desired. So they're making that decision now between now and the end of May. So ultimately, they'll decide upon how long of a term they want and there's already a pre-determined rate for that was embedded within the settlement. And so once they make that decision, that will be effective as of April of 2025. So that's when those rates will go into effect. So we definitely embedded what our expectations are with where we think the customers will end up in regard to their choices of selection.

Operator:

Our next question comes from Gabriel Moreen with Mizuho.

Alan Armstrong:

Yes, Gabe, I would just say our part of that project is on schedule. We're not really at liberty to get into details of the contracting details in that. But remain confident in what we have in the forecast for that project. So anyway, we're not going to speak for the producer. Our part of that project and our work there is on time and team's doing a great job of executing on that, and we'll be ready to serve when we were supposed to be ready to serve on that project.

John Porter:

Gabe, are you referring to Port Arthur?

Unknown Executive:

Chad, do you want to take that?

Operator:

Our next question comes from Neel Mitra with Bank of America.

Alan Armstrong:

Yes. To answer your question, our work on that in terms of developing that project, obviously, was even further ahead of when we announced that. And so you kind of have to remember that as you think about the timing of that. And to answer your question very simply, the degree -- the kind of incremental demand that we're talking about is not reflected in the [indiscernible] project. There might have been some expectation for that. But in terms of the large incremental growth impacts that customers are now starting to reflect in their integrated resource plans. Those are somewhat, I wouldn't say perfectly incremental, but certainly, a big chunk of that is incremental to the load that we're serving on [indiscernible].

Alan Armstrong:

Yes. Well, first of all, there's a lot of productive capability in these fields. And the ability to ramp that up and respond to the market. And I think the producers are managing their business in a way that they will be ready to respond to respond to it, as I mentioned in my comments earlier around gas supply demand balance, that's certainly what we're seeing is producers being willing and able to commit to what they need to on their end to be ready to respond to that. So I think there certainly will be some upside to our business in '25 as the market and supply start to respond to that. But it is typically a very long lag period and very difficult for the market to be able to respond quickly.

Operator:

Our next question comes from Theresa Chen with Barclays.

Alan Armstrong:

Yes. Good question, Theresa. I'll give you my comments, and I'm going to ask Chad to give you a little more detail on that. But I think over time, we have seen the value of storage, and we've certainly seen it with our own Sequent operations. We've seen the value of storage in these volatile markets and markets that are having to respond very quickly to shifts in demand continuing. I think it's also pretty visible to see that both with an increase in renewable power on the market as well as more and more LNG as that comes on LNG is going to need to be a little more responsive. It's not going to run at 100% load factor when the LNG is more -- is closer to meeting the more mature demand from that market. So I think those are a lot of the drivers for the increase in storage capacity.

Chad Zamarin:

Yes. I think it's a really important theme to keep an eye on what both the ability to set up our infrastructure to benefit from volatility and price that supports extraction value. But also importantly, we're seeing the transition. We've been talking about it for a while, increased volatility in power markets, Alan talked about the power demand that we're seeing -- I mean we talk often -- I mean, PJM numbers themselves say that by 2040, peak demand will more than double. That's a significant -- from a set of infrastructure that's already full. And so assets like storage will not only be driven from a value perspective by dislocations in price over time, like the contango we're seeing in the current market, but we are seeing an evolution and a recognition that you're going to need those assets for reliability.

Operator:

Our next question comes from Tristan Richardson with Scotiabank.

Alan Armstrong:

Yes. I would just say as the world turns off of coal, as the reliable baseload and is shifting more and more and more to natural gas as the base load, as Chad mentioned, that reliability issue is going to be really key and us continuing to stretch and deny the amount of capacity we really need in these markets, is going to become a louder and louder drumbeat. You're hearing it from the ISOs already. You're hearing it from -- starting to even hear from the utility commissions about how important it is that they have access to natural gas. You're even starting to hear it in places like Connecticut that are upset that they don't have low-priced gas into those markets because Governor Cuomo stopped a number of projects coming across the state. So it's unfortunate.

Tristan Richardson:

Appreciate it. And then maybe, John, just a smaller one. You appreciate kind of laying out sort of some of the puts and takes in the [indiscernible] segment year-over-year. But is there a number we can think of as what was the organic growth in the quarter? Just thinking about Hartree contributions as well as sort of a partial anniversary of MountainWest?

John Mackay:

Maybe to keep it in the gas demand policy front. You guys have also talked a lot about coal plant retirements on your footprint, you kind of framed up maybe an upside number at the Analyst Day earlier this year. Just be curious, any thoughts you can share on the recent EPA updates around power plant carbon emissions? And how that's playing into your forward view?

John Mackay:

I appreciate all that. Maybe just zooming back in on you guys specifically quickly. Appreciate the frame up of the gas storage opportunity. At the very beginning, you mentioned the rates have come into making brownfield economics work. I guess I'd just be curious like, how much do you think you guys can add on a Bcf basis across your existing footprint from a Brownfield perspective?

Unknown Executive:

I think it's about storage.

Chad Zamarin:

Yes, sorry. Just on storage. We do have quite a bit of capacity at the salt-cavern facilities that we acquired in the Gulf Coast. And so -- and those expansions that we're looking at would likely come in kind of 10 Bcf tranches at each facility. And there is a lot of capacity to expand. I think we're going to be thoughtful about how to do that incrementally as the market kind of recognizes the need. And we're seeing that evolution, but we need to see storage contracts shift from short term to long term for us to support that kind of infrastructure expansion. But it would look like kind of 10 Bcf cavern expansions at those salt-cavern facilities.

Sunil Sibal:

So I wanted to start off -- a little bit big picture question. So it seems like you're executing pretty well on the guidance, the '24 and '25. So I was curious if your actual performance comes out to be above the top end of your guidance ranges? What's the best incremental use of the cash flows in the current environment, especially if this permitting constraints continue?

Alan Armstrong:

Yes, great question. I think right now, as we sit here today. The power gen loads will be pretty strong this summer if the weather predictions that are out there are accurate right now. I think we'll see some pretty strong pools and that pipe and those gas supplies serve that will be capable of responding to that. And that's probably the extent of what we would see here in the immediate term for that, as our expansions that we're working on like the Southeast supply and expansion, system come on in the years ahead, that will start to take full advantage of those incremental supplies. And we'll see areas where we gather the volumes upstream on that benefit from that. But importantly, our ability to expand Transco is a lot lower cost and a lot higher margin for us if we have supply coming in there at 165.

Operator:

This concludes the question-and-answer session. I would now like to turn it back to Alan Armstrong for closing remarks.

Operator:

Thank you for your participation in today's conference. This concludes the program. You may now disconnect.

Danilo Juvane:

Thanks, Bo, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we’ve released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call are Michael Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you will find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. And these reconciliation schedules appear at the back of today’s presentation materials. So with that, I will turn it over to Alan Armstrong.

John Porter:

All right. Thanks, Alan. Starting here on Slide 4 with the summary of our year-over-year financial performance. It was a strong performance by our base business, which we define as excluding marketing and our upstream joint ventures. That base business increase was 6% over the prior year third quarter. As we’ll discuss in a moment, last year’s third quarter saw very favorable commodity prices for our marketing and upstream joint ventures, which did make for a tougher year-over-year comparison in total, but we did still grow total adjusted EBITDA, as well as that 6% increase for our base business. Year-to-date, our total adjusted EBITDA is now up 9%, driven by the growth of our core infrastructure businesses, which continue to perform very well even as natural gas prices decreased 63% for the first nine months of 2023 versus the first nine months of 2022, once again demonstrating the resiliency and strength of our natural gas focused strategy, assets and operational capabilities. So for third quarter, adjusted EPS flipped a little bit from that very strong 2022 number, but you can see, it's still up 11% year-to-date, continuing the strong growth we've had in EPS over the last many years. Available funds from operations was generally flat with last year's strong cash flow and you see our third quarter dividend coverage based on AFFO was a very strong 2.26 times on a dividend that grew 5.3%. Our balance sheet continues to strengthen with debt to adjusted EBITDA now reaching 3.45 times versus last year's 3.68 times. On CapEx, you see an increase primarily reflecting the progress we're making on some of our key growth projects, including Regional Energy Access and Louisiana Energy Gateway. So based on the continued strong financial performance of the business, we now feel confident raising our consolidated adjusted EBITDA guidance to $6.6 billion to $6.8 billion, shifting the midpoint up $100 million from $6.6 billion to now $6.7 billion. In a moment, I'll provide a little color on our expectations for the remainder of the year and a few thoughts regarding the outlook beyond 2023. So let's turn to the next slide and take a little closer look at the third quarter results. We see a 1% overall increase, but a strong 6% increase in our base business EBITDA over the prior year, even as average natural gas prices for the third quarter decreased 68%. Now even for the base business, excluding marketing and our upstream joint ventures, that dramatic decrease in natural gas prices had a significant impact on our revenues. In fact, we saw about $70 million of lower natural gas price based gathering rates at certain of our franchises in the West and Northeast Gathering & Processing segments. Last year, saw those rates significantly lift from the floor values they had been at for many years, and in 2023, we've seen them return back to their floor values. Looking now at our core business performance, our Transmission & Gulf of Mexico business improved $83 million, or 12%, including about a $47 million contribution from our MountainWest Pipelines and NorTex acquisitions, but we did see other increases in our transmission and deepwater businesses as well. Our Northeast gathering and processing business performed well with a $21 million or 5% increase, including a 4% overall increase in volumes versus last year. This 4% volume growth happened even though we saw much lower shoulder season natural gas pricing in 2023 versus 2022. And as we expected, that particularly impacted our dry gas systems, including some significant shut in volumes in Northeast Pennsylvania. However, as we've talked about before, when low natural gas prices weigh on dry gas production, we tend to see a shift to our liquids rich systems where higher margins tend to compensate for lower volumes. And that's what we see in third quarter this year, with about a 22% increase in processing plant volumes fed by those liquids rich systems, with related increases in NGL production, volumes and associated fractionation and transportation revenues as well. So shifting now to the West, which decreased $22 million or 7%, where the unfavorable impact of those lower natural gas price based rates fueled by last year's much higher natural gas prices overcame what was strong volume growth in the Haynesville. And then you see the $22 million decrease in the gas and NGL marketing business. Last year's third quarter saw much more favorable conditions for the gas marketing business with stronger natural gas price volatility in particular. Our upstream joint venture operations that are included in our other segment were down about $52 million versus last year, that includes the Haynesville upstream EBITDA, which was down about $36 million despite higher production, but due to much lower net realized prices and a lower working interest percentage on new wells beginning in January 2023. The Wamsutter upstream EBITDA was down about $16 million, where increases in gas and oil production significantly offset much lower net realized prices versus last year. So again, the third quarter continued our strong base business performance in 2023 with 6% growth and EBITDA driven by core infrastructure business performance in spite of natural gas prices that were 68% lower than third quarter of 2022. Let's turn the page and touch on the year-to-date comparison. Year-to-date, we've seen a 9% increase over 2022, even as average natural gas prices year-to-date fell 63% versus last year. And walking now from last year's $4.6 billion to this year's $5.1 billion and looking at our core business performance, Transmission & Gulf of Mexico business improved $210 million or 10% really on similar themes as our third quarter, namely the impacts of the MountainWest Pipelines and NorTex acquisitions, and still seeing other increases in our transmission and deepwater revenues as well. Our Northeast G&P business has performed very well with $138 million or 10% increase driven by a $217 million increase in their service revenues. And this revenue increase was really fueled by a 6% increase in total volumes focused in our liquids rich areas where we tend to have higher per unit margins than our dry gas areas. And in the appendix, you'll find a slide that compares our 6% volume growth to the overall basin growth of just over 2%. Shifting now to the West, which increased $20 million or 2%, benefiting from positive hedge results and strong Haynesville volume growth, including the Trace acquisition in the Haynesville, but the West was significantly unfavorably impacted by those lower natural gas price based gathering rates and also lower NGL margins. And then you see the $122 million increase in our gas and NGL marketing business, as you'll recall, really caused by the very strong first quarter start to the year for the gas marketing business. Our upstream joint venture operations included in our other segment were down $92 million versus last year. The Haynesville upstream EBITDA was down about $18 million, where the benefits of our 175% increase in net production volumes were more than offset by dramatically lower net realized natural gas prices. The Wamsutter upstream EBITDA was down $74 million due to the combined effects of the historically difficult winter weather we saw in Wyoming this year on production volumes as well as lower net realized prices. So, again, a continuation to the strong start to 2023 with 9% growth in EBITDA driven by core infrastructure business performance with strength from our marketing business that dramatically overcame weaker than expected results from the upstream joint ventures. As I mentioned earlier, we are raising our adjusted EBITDA guidance to $6.6 billion to $6.8 billion with $100 million shift upward in the midpoint. This increase comes thanks to the steady performance of our base business, even after a historic decline in natural gas prices that did lead to some recent shut-ins and also after that historically difficult winter that continued to have unfavorable impacts through April of this year. And this 2023 guidance raise comes after two consecutive years of record breaking adjusted EBITDA growth in 2021 and 2022. In the appendix, you'll see other positive shifts in our financial guidance metrics that are generally aligned with the higher EBITDA guidance. And from a leverage perspective, we finished the year, not knowing the exact timing of when we'll receive payment of the $602 million judgment awarded to us from energy transfer in the recent Delaware Supreme Court decision, as well as the exact timing of the close date of the DJ transactions that we announced yesterday. Our expected payment in the energy transfer matter, net of legal fees will be in excess of $530 million and is still growing every day for interest charges as well. Considering all of these moving parts, we still believe we'll end up close to our original 2023 leverage guidance of 3.65 times, even though that guidance was issued before consideration of the MountainWest pipeline and DJ transactions and about $130 million of share buybacks that we've done this year as well. So, in summary, we are finishing 2023 with a guidance raise that builds on a strong multiyear trend of outperformance and we're setting our sights on continued growth in 2024 before another big growth step up in 2025. And with that, I'll turn it back to Alan.

Operator:

Thank you, Mr. Armstrong. [Operator Instructions] We'll go first this morning to Spiro Dounis at Citi.

Alan Armstrong:

Yes. Hey, Spiro. Thank you. Good morning and thanks for the great question. First of all, I want to clarify one thing, because it might have got confused a little bit in the commentary. When we talk about this potentially delivering another phase of expansion there, the EBITDA that I'm talking about and the scale of the EBITDA is on this initial phase. So we're not counting on a second phase to grow that EBITDA to that kind of scale, just to be clear. So that EBITDA that I mentioned, being larger – being the largest and being larger than our entire Northwest Pipeline system is on the initial 1.4 Bcf/d for clarity on that topic. In terms of returns, we're not going to put that number out there right now, but I can tell you, it's one of the most attractive returns we've ever seen for any pipeline expansion of scale. And we're really excited that capacity is precious, coming out of there. And just to remind you on the physical capacities that we have out of there, the total physical capacity out of there is 5.7 Bcf/d, 2.5 to the north, 2.5 to the south, and 700 million a day on the Virginia lateral. So that's the existing capacity that we have out of there, physical capacity that we have from 165 today. Obviously, there's a lot of demand for that and capacity, and so it's not like it's just sitting there available for somebody to come in and buy. And that's obviously why we're able to put together such an attractive project here. Utilizing – by the way, utilizing our existing right away and obviously structuring that in a way that will be provide the least points of resistance from a permitting standpoint for expansion south on that. So actually not a terribly complicated project. Easy for me to say that I don't have the responsibility for getting that done directly, but it is on our existing right away and avoids a lot of the typical area wetland problems that we get into and tend to snag the permitting process. So, great job by the team on working with our big customers out there of meeting their very urgent needs on this and providing a very attractive project. So couldn't be prouder of the team and the way they've worked through this.

Alan Armstrong:

Spiro, I'm going to have Chad Zamarin take that.

Spiro Dounis:

Got it. Helpful color. Thanks, Chad. Thanks everybody.

Operator:

Thank you. We'll go next now to Neel Mitra at Bank of America.

Alan Armstrong:

Yes, it's a great question actually. And I think the market will figure that out. I think the way, for instance, our LEG project is structured, that will give people the opportunity as they come in there at [indiscernible] that'll give Haynesville producers the options of either moving down the traditional path on Transco towards 85 and into those markets or selling into LNG, whichever their preference is. And so that's the beauty of the Transco system is it gives people those options and the networking effect of our entire system gives people greater market options that they'll appreciate. So I'm not sure that people will have that a producer, for instance, will have to declare one way or the other on that as much as they'll be positioned to enjoy the benefits of either one of those markets. But we certainly are going to see, I think, competition for Haynesville supplies that have traditionally come in, a lot of that's come into Station 85 and that will certainly be in competition with 165 for a while. And that'll really dictate which way the volumes flow on there. But as those big LNG – and the LNG capacity growth is not all that hard to predict. The projects are out there and they're hard to sneak up on anybody just because they're so big and take so long for permitting. So that LNG market is becoming very evident and it will certainly take away supplies that a lot of the Transco customers have depended on coming in Station 85. And I do think to your point, I do think that's why we're seeing such an interest in picking up supplies off of Mountain Valley Pipeline. But I also tell you that largely just because the markets are growing in those areas is really what's driving that as they really start to run out of options for meeting power generation loads in those areas.

Neel Mitra:

Great. And then my follow up, your Texas to Louisiana Energy Pathway Project, I think it’s roughly $364 million a day in 2025. And it seems like crossing the border between Texas and Louisiana is actually harder than we initially expected. What are the opportunities for you to be able to move Transco volumes from South Texas, whether they’re sourced from the Permian or Eagle Ford up to the Louisiana Energy Corridor with compression or even looping in what are kind of the impediments towards scaling up the size of Transco to be able to do that?

Neel Mitra:

Got it. And just to follow up on that answer, what’s the FERC lag in terms of approving a loop. I know compression is much easier. I think that’s what you did with Texas to Louisiana pathway. But how much harder would it be to get the regulatory filing for a loop on Transco once you make that compression on that front?

Neel Mitra:

Great. Thank you very much.

Theresa Chen:

Good morning and thank you for taking my question. First, on the DJ acquisitions, if 7x is stand-alone, how low do you think you can bring that in multiple with the downstream synergies? And are there additional opportunity for and portfolio optimization going forward?

Theresa Chen:

Got it. And thus far into fourth quarter, can you provide some color on the progress made to date on the marketing efforts, just given the seasonal tailwinds this winter?

Theresa Chen:

Thank you.

Jean Ann Saulsbury:

Hi good morning. Congrats on the Southeast Supply Enhancement precedent agreements. I just had a couple of questions on that. Does the spin start when MVP goes in service, and therefore, kind of the clock. So the 4Q 2027, if basically MVP starts a lot later than expected, that would also push back?

Jean Ann Saulsbury:

Got it. Yes, I think I meant more for you to have the project online. If Mountain Valley gets pushed, would your start date also kind of get pushed because you would wait to start working on it.

Jean Ann Saulsbury:

Got it. That makes sense. And is it all going to be kind of the 1.4 Bcfd, and kind of all one day kind of shows up – not one day, but at one time? Or could it be sort of phased in gradually leading up to the final.

Jean Ann Saulsbury:

Got it. And then another follow-up. I think most people believe that we’re entering a period of significantly more volatility in gas price both in regional spreads and in time spreads. Can you kind of just walk us through the specific part of Williams portfolio that would benefit from this over time versus this year, which wasn’t particularly volatile? I know that there’s sequence, obviously, in but also sort of market rate storage, the gas-linked gathering contracts that you referred to, et cetera?

Chad Zamarin:

Yes. I think you mentioned several of them. I think the fundamental base business benefits, I mean, at the end of the day, pipeline infrastructure is built to mitigate basis. I mean, so we like the setup certainly near term from a marketing, from a storage and optimization perspective. It’s obviously drives the need for our producers and our supply areas to be better connected to different markets. But ultimately, volatility and basis differentials are what drive value across our core infrastructure. And that’s why we think we’re set up so well to continue to grow our base business and layer in is kind of the cherry on top, layer in these other assets and capabilities that capture that volatility. But at the end of the day, our business is converting volatility in infrastructure, and that’s really what we’re focused on. And we think we’re really well set up to follow basis differentials and volatility and bring infrastructure solutions to help mitigate that long term.

Chad Zamarin:

Thanks.

Brian Reynolds:

Hi good morning everyone. Maybe to peak ahead to 2024, excluding today’s acquisitions. We have some tailwinds around full year Mountain West and some small expansions also by some hedging headwinds, it seems like, but kind of just curious if you can maybe just talk about the existing base business and whether there are any rising ties as it relates to volumes or kind of what Jean Ann alluded to some nat gas storage opportunities or margin uplift that could move the needle one way or the other next year as we think about just the 2024 versus 2023? Thanks.

John Porter:

Not a lot really to add. I do think a really good reference for information about our growth in 2024 and really beyond is in Slide 18 in the appendix, you’re going to spot a number of projects, as Alan mentioned, that will contribute to 2024 based on what we know today, including several projects in the transmission and Deepwater Gulf of Mexico business as well as several gathering and processing expansions. You mentioned the full year of MountainWest Pipeline acquisition and now these DJ transactions that we’re discussing today, too, that will layer into 2024. And you also mentioned working against these increases, we will see the absence of some of the gathering and processing related hedges that we had in place in 2023. But again, that’s Slide 18 in the appendix, I think, really clearly shows the projects that will be leading to the growth of 2024 and obviously, the much more significant growth in 2025 and beyond. And as Alan mentioned, it kind of shows you the different projects that could potentially add to upside if we’re able to bring them in early.

Alan Armstrong:

Yes, Brian, thank you. We’re pretty careful to not put things in there until we’ve got pretty high level of optimism about those projects going forward in that backlog. And I would tell you, I would be frankly very surprised if we didn’t see some – a lot of those projects that are in our pipeline move forward, given the amount of demands and projects that are coming on and the way we’re positioned with our infrastructure to serve that. So to answer your question, I think it would be very unlikely that we wouldn’t see some additional projects come in to help serve a lot of these gas demand increases. And I say that from a few fronts. One, if you look at what the alternatives are for power generation, say, in the Northeast now, the answer for power generation up there was going to be offshore wind, that is looking very unlikely now within the decade that we’re looking at right now, and so some other answer is going to have to happen. Unfortunately, we’ve shut down the Indian Point Nuclear Facility, and there’s pressure to take down other facilities up there. And I just think that’s – people are going to have to get sober pretty quickly here on what the alternatives are up there. I think our customers on REA are going to wind up looking really, really smart for taking that capacity that they took because I think that’s going to be in precious demand. So in the Northeast, I think harsh reality is going to set in here before long. In the Mid-Atlantic, we saw great evidence of demand well beyond what this initial project that we’re building in the Mid-Atlantic States and into the Southeast. And then obviously, the LNG market continues to demand more and more infrastructure in that area that we’re well positioned to serve. So it would be pretty shocking to me if we didn’t see that – a lot of that backlog into 2025 and 2026 really turned into some pretty material projects up there.

Alan Armstrong:

Thank you.

Tristan Richardson:

Hey, good morning, guys. Alan, you noted in your comments, you’re surprised at the level of demand you’re seeing as you seek to commercialize healthy supply. I mean, suggesting that there could be other opportunities. Is this a dynamic where the scope of Southeast Supply could change over time? Or are you thinking of addressing this demand really with separate projects and thinking way down the road?

Tristan Richardson:

That’s great context. And then as we look out to 2024 and the acceleration of EBITDA growth into 2025, is there a thought about the appropriate pace of dividend growth relative to your 5% to 7% long-term EBITDA growth, particularly with the visibility you guys have over the next couple of years. And as we’re seeing the midstream space broadly return to a period of accelerated dividend growth?

Tristan Richardson:

Appreciate it, Alan. Thanks all.

Jeremy Tonet:

Hi, can you hear me now?

Jeremy Tonet:

Thank you. Good morning. Just wanted to start off, if I could, with regards to capital allocation. And just wondering, as you’ve talked about it in different points of the call, but specifically as it relates to higher rates out there, how that impacts, I guess, thoughts on return of capital hurdles for capital deployment, specifically thinking about the dividend rate now, price appreciation has increased the yield a bit. Just wondering how this all mixed together with higher rates today?

Alan Armstrong:

Yes. And I would just add at a macro level there, Jeremy. The strange as it may seem, the higher interest rates are actually on a macro level, I think, pretty good for this business and a couple of reasons. One, given the structure of our gathering contracts and the inflation adjustment in those, which goes against the entire rate, not against just the operating cost side of that rate. So that really continues to push our operating margin up. I would tell you that we don’t plan on the inflation rate continuing as we look to our long-term model. But to the degree that occurs, it’s actually a net positive for us. But in addition to that, I think you’re seeing the impact of high interest rates come across the alternatives as we think about power generation and infrastructure to meet power generation demand. And in a simple term, a gas-fired generation facility has a huge advantage on the capital costs associated with it, but as a disadvantage on the fuel cost. And so the fixed capital element of power generation is very positive from a natural gas standpoint just because of the capital required on the front end is so much lower, but the savings are in the fuel. And so I think we’re in a very attractive environment right now for our business in our industry in general as interest rates have moved up. It’s just put more and more pressure on people’s need to have natural gas as a very real-world alternative to meet the very rapidly growing power generation demands that we’re seeing in the markets we serve.

Operator:

Thank you. We’ll go next now to Praneeth Satish at Wells Fargo.

Alan Armstrong:

Yes. I think for a number of reasons. I think even some of the shifts we’ve seen here in the mid-Atlantic states are the rapidly growing demand that they’re seeing from things like data centers and all kinds of incremental loads that they’re seeing, even industrial load from the fact that we have such low priced gas here in the U.S. is driving some of that demand. So yes, we’re seeing that mostly in the Southeast and Mid-Atlantic states. I think the Northeast is yet to come. I think people have kind of been holding out for that. And I think there’s been plans to depend on that offshore wind and I think, as I mentioned earlier, I think the harsh reality is going to hit us there. So we’re – we very much see ourselves as a complement to renewables, and we are all for seeing that develop. But here as we sit in the Northeast to answer your question, we haven’t seen the shift or the capitulation perhaps you might describe it as in that market yet. But I would say we certainly are seeing a very sober mid-Atlantic and Southeast markets because they’ve been up against the – they’re seeing the demand growth in their markets, and they’ve got to have an answer for it.

Praneeth Satish:

Got it. And then switching gears on Overland Pass. Do you see any disruption to volumes on the line after ONEOK expands Elk Creek if they decide to divert volumes, will that impact Bakken flows on Overland Pass? And then, I guess, if so, would you expect some of the NGLs picked up from the DJ assets? Could that potentially backfill any volume loss on OPPL?

Praneeth Satish:

Got it. Thank you.

Alan Armstrong:

Okay. Well, thank you. Thank you all for joining us today. Really exciting to get to announce a lot of accomplishments in the quarter and a real, I think, very clear picture of the kind of growth that we are seeing emerge ahead of us. And so very excited for the current performance, but even more excited about the growth and the signs of even more growth that we’re seeing in – across our strategy right now. So thanks for joining us, and I look forward to speaking with you next time.

Danilo Juvane:

Thanks, Bo, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we’ve released our earnings press release and the presentation that our President and CEO, Alan Armstrong and our Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call today are Michael Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you will find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. And these reconciliation schedules appear at the back of today’s presentation materials. So with that, I will turn it over to Alan Armstrong.

John Porter:

Thanks, Alan. Starting here on Slide 3 with a summary of our year-over-year financial performance, beginning with adjusted EBITDA, we saw another strong quarterly increase of 8% over the prior year, and this happens to coincide with an 8.6% CAGR over the last five years for this same measure. And this strong performance included a new record for gathering volumes, which increase 6%. Year-to-date, our adjusted EBITDA is now up 13% driven by the growth of our core infrastructure businesses, which continue to perform very well, even as natural gas price decreased 61% for the first half of 2023 versus the first half of 2022, once again, demonstrating the resiliency and strength of our natural gas focused strategy, our assets, and our operational capabilities. For second quarter, our adjusted EPS increased 5% for the quarter, continuing the strong growth we’ve had in EPS over the last many years with our year-to-date EPS now up 23%. Available funds from operations AFFO growth for second quarter was in line with adjusted EBITDA and you see our second quarter dividend coverage based on AFFO was a very strong 2.23 times growing about 2% despite growing our dividend by 5.3%. Our balance sheet continues to strengthen with debt to adjusted EBITDA now reaching 3.5 times versus last year’s 3.82 times and that’s even after closing the Trace, NorTex and MountainWest acquisitions and also repurchasing $139 million worth of shares since last year. On CapEx, you see an increase primarily reflecting the progress we’re making on some of our key growth projects, including Regional Energy Access and Louisiana Energy Gateway. For the full year, there’s no change to our consolidated adjusted EBITDA guidance of $6.4 billion to $6.8 billion or any of our other guidance metrics. But in a moment, I’ll provide a little color on our expectations for the remainder of the year versus the performance we’ve seen thus far in 2023. So let’s turn to the next slide and take a little closer look at the second quarter results. A strong 8% increase in EBITDA over prior year even as average natural gas prices for the second quarter decreased 71% walking now from last year’s roughly $1.5 billion to this year’s $1.6 billion, we start with our Upstream joint venture operations that are included in our other segment, which were down $43 million versus last year. Our Haynesville Upstream EBITDA was down about $14 million despite substantially higher production due to much lower net realized prices and a lower working interest percentage on new wells beginning in January of 2023. Our Wamsutter upstream EBITDA was down $29 million due primarily to lower realized prices, but production also continued to be impacted throughout April from the historically difficult Wyoming winter weather we saw in the first quarter. Shifting now to our core business performance, our transmission in Gulf of Mexico business improved $96 million or 15%, including about a $52 million contribution from our MountainWest Pipeline and NorTex acquisitions, but with other increases in our transmission and deepwater revenues as well. Our Northeast G&P business performed extremely well with a $65 million or 14% increase, driven by an $81 million increase in service revenues. And we did have a one-time $14 million favorable gathering revenue catch up adjustment in that second quarter increase in service revenue. But this revenue increase was really fueled by a 6% increase in total volumes in the Northeast. Shifting now to the west, which increased to $16 million or 5%, benefiting from continued strong volume growth in the Haynesville and positive hedge results that partially offset the impact of lower commodity base rates. And then you see the $22 million decrease in our Gas and NGL Marketing business and the majority of this decline was actually related to lower NGL marketing results from inventory valuation changes where we had to gain on NGL inventories last year at a loss this year. So again, the second quarter continued our strong start to 2023 with 8% growth in EBITDA driven by core infrastructure business performance in spite of natural gas prices that were 71% lower than second quarter of 2022. So let’s turn the page and touch on the year-to-date comparison. Year-to-date, we’ve seen a 13% increase over 2022, walking now from last year’s $3 billion to this year’s $3.4 billion, we start with the upstream joint venture operations included in our other segment, which were down $39 million versus last year. Now, year-to-date, Haynesville is up nicely on very strong volume growth that has been significantly offset by lower realized prices. However, the overall Haynesville increase was offset by lower Wamsutter results due primarily to the historically difficult winter weather we saw in Wyoming this year. Shifting now to our core business performance, transmission in Gulf of Mexico business improved $127 million or 9% that’s really similar themes as our second quarter, namely the impacts of the MountainWest Pipeline and NorTex acquisitions, however, we have seen other significant increases in our transmission and deepwater revenues as well. Our Northeast G&P business has performed very well with $117 million or 13% increase driven by $154 million increase in service revenue. This revenue increase was fueled by a 7% increase in total volumes focused in our liquids rich areas where we tend to have higher per unit margin than our dry gas areas. And in the appendix, you’ll find a slide that compares our 7% volume growth to the overall basin growth of just under 2%. Shifting now to the West, which increased $42 million or 8%, benefiting from positive hedge results and the Trace acquisition, but the West was significantly unfavorably impacted by the severe Wyoming weather and January processing economics at our Opal Wyoming processing plant. And then you see the $144 million increase in our Gas and NGL Marketing business caused by the strong first quarter that we had at the start of the year. So again, a continuation to the strong start to 2023 with 13% growth in EBITDA, driven by core infrastructure business performance with strength from our marketing business that dramatically overcame weaker than expected results from the upstream joint ventures. So as I mentioned earlier, there’s no change to our consolidated adjusted EBITDA guidance of $6.4 billion to $6.8 billion or any of our other guidance metrics. We’ve definitely had a strong start to the year with $3.4 billion of EBITDA through the first half of the year. And thanks to the performance of our base business we have clear visibility to hitting at least the mid-point of our guidance even after a historic decline in natural gas prices and a historically difficult winter that continue to have impacts through April. So you may be wondering, why we aren’t raising our guidance on the back of such a strong start to the year and a bright future ahead. First, I will remind you that our guidance does include a range of $200 million above our midpoint. And second, while we usually experience stronger third and fourth quarters than second quarter, the third quarter does occasionally see hurricane outages for our deepwater business. Finally, we could also still see downward shifts in natural gas prices for the balance of the year that could unfavorably impact our upstream joint ventures in particular. While we are not suggesting, there is a high likelihood of realizing these impacts, we do need to be prepared to overcome these scenarios. Therefore, it is too early to raise our full year guidance. But once again, we are confident in the continued performance of our base infrastructure businesses, allowing us to once again meet or exceed the midpoint of our guidance range. We’re setting our sites on continued growth in 2024 before another big growth step in 2025. And with that, I’ll turn it back to Alan.

Operator:

Thank you, Mr. Armstrong. [Operator Instructions] We’ll take our first question this morning from Spiro Dounis at Citi.

Alan Armstrong:

Yes. Spiro, well, certainly, I wouldn’t say, there’s one answer to that question, but maybe I’ll try to summarize it a little bit. I think the majority of producers see a pretty bright future for demand right now. And as a result of that, they’re making sure that they’re not letting their systems fall into decline in a way that’d be hard to recover from. So I would say, they are much like a cat kind of poised for demand growth in the future, but really watching cost and trimming out cost where they can and kind of proving up their capabilities in certain areas. So I would say, it feels to me like the producers are trying to maintain level volumes as much as possible, but being poised for future demand growth, that’s pretty evident down the road.

Alan Armstrong:

Yes. I would just say, I think we really enjoy the flexibility that we have right now and we’ve been pretty clear about capital allocation. It’s nice to have a – such a large pool of ability to invest in our rate base at some pretty decent returns, and I think probably even some higher returns once we get through the next rate case, given the inflation and the cost of debt that’s gone up, that will drive us to be able to earn even an higher return in our rate base. So that’s really nice to have that pool of capital to be able to invest in. And that really kind of sits at the bottom of our stack of capital allocation, but team’s doing a great job of deploying that. As I mentioned, we completed our Station 180, which is a very large compressor station in [indiscernible] and the team brought that in a little bit ahead of schedule, and Michael and I actually got to go up there a few weeks ago and see that great effort by the team of modernizing our facilities there. And so anyway, I would just say to answer your question more directly, we have places to place capital for nice return like that and I think we’ll continue to do that, but we certainly enjoy the flexibility that we have at this level to be able to place capital towards those kinds of opportunities.

Operator:

Thank you. We go next down to Jeremy Tonet at JP Morgan.

Alan Armstrong:

Good morning, Jeremy.

Alan Armstrong:

Yes. I definitely think we saw producers focusing, where they have it available. We saw producers focusing on wet where there are producers that have that ability to shift. But while at the same time, I think keeping themselves poised for markets to open up. And so I would say, that’s kind of what we’ve seen. In terms of normalized EBITDA, I think the first two quarters are a pretty good sign of that. I think anytime you can just average that out over a couple of quarters, I think that’s a pretty good sign of a normalized number. But I do think as markets open up through both MountainWest and Regional Energy Access and continued industrial and power generation demand in the local markets, I think we’re going to see that PJM, certainly found itself very short power lasts year or – and during the winter time as well. And I think we’re going to continue to see people build out power generation to take advantage of that. So I’m pretty encouraged, frankly, about in terms of the market outlook over the next couple of years for the Northeast. I do think that we’ll see the Northeast have an opportunity to take back some of the market share across the U.S. as a result of some of these markets opening up.

Alan Armstrong:

Well, there’s really three distinct issues there. Mountain Valley Pipeline certainly, and it’ll be competing. There’s been some confusion out there. I think in the market, we have plenty of capacity to pull all that MountainWest can deliver. It’s just a question of how it’s going to compete with Haynesville gas coming in at Station 85 on the system. And so there – but there’s – it’s just going to be a question of producers competing for those markets. But I will say that market in particularly at south of Station 165, as was demonstrated by a recent open season is going to continue to grow pretty rapidly. And last winter got caught in a very short situation on natural gas. And so we’re going to continue to see the markets in the Carolinas there and Virginia and the Southeast continue to expand. Mountain Valley Pipeline’s going to be that connection. In addition to that Regional Energy Access is also going to provide new market and that’ll take some time. It’s not going to be a snap your fingers and we’ll see that kind of growth pulled out of that area, but it will open up new markets and new demand. And then finally, as I mentioned, regional loads in the area as well and people taking advantage of low price natural gas, and in fact, the shell big cracker there is just one good example of the industry growth, but as well we’re seeing power generation load to continue to build there as well in the PJM area. So I think really pretty clear examples of market growth for the Northeast.

Alan Armstrong:

Yes. I think as we mentioned, the open season that we had for capacity south of 165 really kind of caught our attention, frankly, and far exceeded our expectations. And so when we say that it exceeded what we had to offer, it was a very large multiple versus what we had to offer there. So yes, we definitely are seeing the signs of people taking advantage of low price natural gas. And importantly, I think this is something that gets missed too often, Jeremy, I know you follow this, but I think sometimes the broader investor base misses this that – what we have to sell is capacity. It doesn’t mean that that’s going to be an annual average increase in volume as much as it does mean that people are absolutely going to have to buy capacity for those peakers and for baseload. And we actually, I think we’re going to see quite a bit of baseload pick up as well, because the amount of data centers, the amount of electrification load that’s going on is well in excess of what our increasing wind and solar generation can keep up with. And so we’re not only going to see peaking, we’re going to see baseload increase as well. But again, all of that boils down, whether it’s peaking or it’s baseload, people still have to buy the full amount of capacity on our pipeline. And that’s certainly coming through in these open seasons that we’ve been having on – in that area.

Alan Armstrong:

Thank you.

Jean Ann Salisbury:

Hi, good morning. I just wanted to follow-up on the comment that was just made Alan about there being plenty of capacity on Transco and it kind of being a competition between the Haynesville producers and the Appalachian producers. I think that for the open season for the 800,000, that timeline is kind of set for 2027. So is it accurate to say that capacity is there, but sort of needs to be unlocked to be usable over the next few years?

Jean Ann Salisbury:

Okay. But they’re kind of – I guess, maybe my broader question is like, if – like, there need to be projects that Williams does that are kind of negotiated rate incremental contract.

Jean Ann Salisbury:

Got it. That makes sense. Thanks. And then as a follow-up, there was a big tick up in NGL and crude volumes that you classify as Overland Pass and Rocky Mountain Midstream this quarter. What was driving that?

Jean Ann Salisbury:

Great. That’s all for me. Thank you.

Operator:

Thank you. We go next now to Brian Reynolds at UBS.

John Porter:

Yes. I think we want to have a lot of confidence in hitting our midpoint. So we do account for things that could happen around the hurricane season and perhaps additional weakness that could come, as I mentioned, from a further decline in natural gas prices. So we’ve built in some ability to handle those kinds of downsides relative to making sure that we can hit our midpoint. So I think conversely, the things that would move us higher in the range would just be better than forecasted performance in the underlying gathering and processing systems in the base business, which is always possible. And it is also possible that we could have a stronger marketing result in the fourth quarter. Sometimes we have fairly strong for example, Novembers and Decembers, but that is unpredictable. Most of that performance comes in the first quarter. So we don’t like to overly depend on any kind of a marketing result to make the numbers. And so we got a lot of confidence just from the base business around hitting the midpoint of our guidance and certainly think we could exceed it as well, but still fairly early in the year and just weren’t comfortable yet in raising the guidance.

Alan Armstrong:

Brian, I would just add – yes, I would just add to that. On the natural gas – sorry, on our marketing business that I think it’s really important to recognize that really what drove the negative in there was primarily just the markdown on NGL inventory. So that’s just – that’s not really cash, moving through the books, it’s just a change in price on the inventory that we hold. And so unless you – if we were to mark that book right now, obviously, you’d see a pretty big step up in that, just because ethane prices have come up so much. But I think that’s really important for the Street to understand relative to balance of the year.

Alan Armstrong:

Yes. Thanks, Brian. Well, I would tell you we are engaged in a number of projects there. And we’re not in a position to be able to disclose those at this point, but we are involved in some pretty large scale projects that we’re excited about and we think we’ll add a lot of value to our shareholders as well as the industry in general and much needed. So we’re pretty excited about that, but we’re not in a position yet to disclose exactly what’s going on there.

Alan Armstrong:

Thanks, Brian.

Praneeth Satish:

Good morning. I guess, on Southeast Supply Enhancement, first, do you think the project could be upsized given that you noted a very strong open season? And then I guess, I’m still confused maybe a little bit on the lead time. The lead time for the project seems pretty long. It has an in-service date of Q4 2027. Is there anything in particular causing the timeline to be that long or is there may be a contingency in there for permitting?

Praneeth Satish:

Okay. That makes sense. And then I guess, just looking at the futures curve for natural gas, it’s in Contango, it’s pretty wide winter, summer spread right now. Just wondering if you could kind of talk through your ability to capture that at Sequent. I guess how much storage capacity does it have right now and how much of that is open and able to take advantage of these wider spreads?

Alan Armstrong:

Yes, I would just add to that, the way we would book those earnings, we actually would not book those earnings until we delivered. And so that’s really why our fourth – sorry, our first quarter is usually pretty sizable for us is that’s when you see the pricing and the most value for that storage is usually offered in that period. And so that’s a great example of why our first quarter tends to be so large. Some of that, like we said, make them in the fourth quarter depending on what pricing looks like and if we can cycle that storage twice, but we do have to cycle it to be able to take the earnings on that.

Operator:

We’ll go next now to Colton Bean at TPH and Company.

John Porter:

No, I think really – as was asked earlier, the question of rich versus lean, obviously when there’s more rich gas drilling, there’s a lot more services that we offer around that. And so that does – that shift to richer gas does tend to drive our margin – our unit margin up across the basin.

Alan Armstrong:

Yes. Right.

Michael Dunn:

Yes. Colton, thanks for that recognition. Yes, the team’s doing a great job controlling our costs even in this inflationary environment. We have found some ways to actually continue to take cost out of the business and as you’ve indicated, the MountainWest acquisition is really the cost increase that we’re seeing there on the e-comm side of the business. And so I think going through the balance of the year, we would have an expectation that we can continue that cost control. Now, there’s always a lot of variability throughout the second and third quarters with our maintenance activities and our overhauls that are recurring and that would be the only variance that we would see there typically coming up between the second and third quarter, but other than that team’s doing a great job controlling costs this year.

Operator:

We’ll go next now to Neel Mitra of Bank of America.

Alan Armstrong:

Yes. Neel, let me try explain it one more time. The way the most of the system rates work on there, the shippers have pay the same price, they pay us no matter where the gas is moving from. Generally the – those utilities in that corridor have the ability to pick up gas and they have a volume available that they can pull from at various receipt points. And so they basically are out trying to buy the lowest price gas on the system that they can have delivered into their meters every day. And when we talk about system capacities, we’re actually talking about kind of the delivery capacity to those locations, and it’s – this particular path that somebody buys capacity from on the system. But the big long haul system and the original base system, the shippers have the ability to choose where they want to pull their supply in from. And so even if they’re – we have a number of expansions going on, but even if you just looked at it in a static environment, if somebody today was buying gas Station 85, that gas is likely coming in from either system gas on in the Offshore or Haynesville or gas that’s made its way in from the Permian. But Station 85 or 65 would be a place that customers would be nominating their supplies from and they’d be buying gas from maybe a Haynesville producer at Station 85. If they – if somebody from the Marcellus decides, they want to sell their gas cheaper at 165, then that customer’s going to be able to say, well, I’m going to nominate from Station 165 – at the 165 location instead of 85. Same amount of gas eventually flows to their delivery point. But it’s just a matter of where they source their supply from. So in – so we – it’s just going to be a question of where producers decide to sell their gas set and who wants to compete the most for those supplies. As we build out the system and the demand then matches back up to that supply then the system would be back in balance. And – but that’s the way it always worked. There’s always periods where supply builds up because you have more supply locations, then you have delivery, and then eventually you build out the delivery market like we’re doing in all these projects. And then more supply is needed, which is kind of the situation at Station – sorry, at Zone 5 right now. People got caught short there in the winter because there was not enough supply coming in there. So MVP will provide that needed supply that was missing this last winter.

Alan Armstrong:

Well, it doesn’t have to just move South. It can move North and South. So I think that’s maybe the missing concept there is the gas can – will move wherever the market is, but we certainly have more demand on the system in both directions from 165 than 2 Bcf a day.

Alan Armstrong:

Thank you.

Tristan Richardson:

Hey, good morning, guys. Just curious your views on the transmission M&A landscape. I mean, it seems like the funnel of assets in the market is really only growing and clearly we’ve seen a lot of transactions clear the past 12 months, even if they’re passive stakes. Have you just seen more opportunities that would potentially be a strategic bid? And then do you see these multiples as attractive in transmission with some of the transactions we’ve seen clear?

Tristan Richardson:

That’s helpful, Alan. And then maybe just a question on MountainWest, I mean, with the Overthrust Expansion, sounded like that was maybe incremental to your expectations or at least what you saw as the opportunity set for the acquisition at the time of close. Maybe curious kind of is one of potentially other expansions that it could occur. And then maybe if there’s anything on the scale and timing of that project that you didn’t already mention.

Michael Dunn:

Yes. Tristan that was not in our pro forma economics for the acquisition. So it’s certainly a pleasant upside there with the MountainWest acquisition. This is about an 11% increase in the Overthrust capacity for the 325,000 dekatherms a day expansion. And it’s a pretty simple expansion. It is two compressors that we’re adding at existing compression facilities on that system, but there’s definitely more upside opportunity there. There seems to be a desire to get more gas Westbound toward the Opal pricing point. That’s been a pretty solid pricing point for a number of years now. And even this summer, we’ve seen gas trading at $4 there at the Opal hub, even higher than that, just driven by California economics with the heat that hits California this summer and gas generation that’s picking up there. So I would expect to see a lot of desire for customers to get to that Opal pricing point. And that certainly bodes well for Overthrust at the direct connection into that hub. And as far as the rest of the MountainWest system, we see a lot of opportunity there for coal to gas switching. There’s a number of very large coal-fired power plants in Wyoming and Utah that do have opportunities for conversion to natural gas. And some of those we’ve already acquired and we’re actually building expansions for off the Overthrust system today in Bridger Units 1 and 2 in Wyoming on the [indiscernible] system are converting to gas. And we’re building a pipeline over to the – that facility this year. So we’ll continue to see opportunities like that on the MountainWest system and those are certainly upside opportunities, not only for us, but gas will be sourced out of the Wamsutter field with our Upstream production and we’re driving that gas to those markets as well with the secret platform.

Operator:

Thank you. We go next now to Gabriel Moreen at Mizuho.

Alan Armstrong:

Yes John, you want to take the first part of that and I’ll take the last?

Alan Armstrong:

Yes. And Gabe, I would just add to that, I think in terms of our approach to hedging on the E&P side, we have been putting on some April through October hedges for gas in 2024. And as John said, large – so part of that’s driven by the fact that we don’t really want to get caught short in an up market. I think everybody experienced that a couple of years ago. And so we tend to not get ourselves in a position where we could get caught short on production, particularly since we don’t operate that production. So that’s how we think about hedging on the E&P side there. So – but in terms of the – in the broader scheme of things, in terms of transactions around E&P, I would just say we continue to entertain a lot of interest in that. And I would just say I – as we look at the landscape and the demand that’s building for not just – everybody’s very focused on LNG and we think obviously that’s going to continue to be a big driver for demand, but the macro picture we’re seeing around electrification and the amount of power demand increase that continues to build in this country is pretty impressive. And we’re also seeing a lot of industrial demand pick up in and around our assets as well, and things that were previously powered by either fuel oil or coal or onshoring ammonia production here in the U.S. there’s just a lot of demand building and we have a pretty good insight to that. So it’s kind of seems shortsighted to get in a hurry to sell out particularly at like the Haynesville where the team, the GeoSouthern team has done a great job there and they continue to find ways to lower cost and increase production there. So we think both from their operational capabilities, which we’re enjoying and the macro fundamentals around gas is just not really a compelling reason to liquidate in this environment.

Michael Dunn:

Hey Gabe, it’s Michael. Yes. We just put in service at Station 180 replacement. We’ve replaced 14 units there with two new state-of-the-art turbines, and we’ve got three more stations that will be very similar fashion coming on before the test period closes on the rate case. And so that’s the anticipated bin curve there, similar to what we did on 180. And its really highly dependent after that on the rate case outcome and whether we get an emissions tracker, which we would certainly hope to achieve on the Transco rate case, similar to what we were able to do on Northwest Pipeline. And that would really drive our decision making in the near-term on spending beyond the 2024, 2025 timeframe. And we layer that into what our next rate case tranche looks like on the Transco system and really try to balance that spending curve where we think those rate cases are going to line out there in the future. But obviously hoping to go into this one with an emissions tracker, modernization type tracker coming out of the negotiated settlement that we hope to achieve with the Transco customers and we’ll see how that turns out.

Operator:

We’ll go next now to Neal Dingmann at Truist.

Alan Armstrong:

Yes, really good question. I would say that we’ve said all along that we expect this business to generate in the 5% to 7% growth on EBITDA and that we would expect that to keep our dividend somewhat in line with that. And so I think as we think about it forward AFFO per share really is the number I think to keep your eye on that’ll drive our decisions on dividend looking forward. And so I think that’s a really good number for you to focus on. But yes, we certainly have plenty of room, plenty of capacity and in terms of that dividend increase, and it’s just going to be driven by what we’re seeing as a kind of a long-term sustainable AFFO per share is really what’s going to drive our dividend decisions.

Alan Armstrong:

Thank you.

Robert Catellier:

Hi, Rob Catellier, I just wanted to follow-up on capital allocation this time on M&A. So understanding that you’ve been quite active in the last 18 months or so. Can you comment on the company’s appetite for additional acquisitions and maybe on the state of the M&A market understanding that maybe MountainWest was a little unique. So just how the low commodity prices and higher interest rates are impacting bid of spreads?

Robert Catellier:

Okay. That was the color I was looking for. Thank you.

Alan Armstrong:

Okay. Well, thank you all for the great questions this morning. Thank you for your continued interest in the company and we just want to reiterate how excited we are about our continued growth on top of growth here in the business and our abilities to demonstrate our resilience this quarter and we appreciate your confidence in our company. Thank you.

Danilo Juvane:

Thanks, Abby and good morning everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we have released our earnings press release and the presentation that our President and CEO, Alan Armstrong and the Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call today are Michael Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you will find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. And these reconciliation schedules appear at the back of today’s presentation materials. So with that, I will turn it over to Alan Armstrong.

John Porter:

Thanks, Alan. Starting here on Slide 4 with a summary of our year-over-year financial performance, beginning with adjusted EBITDA, we saw a 19% year-over-year increase. As we will see on the next slide, our adjusted EBITDA growth included growth of over $100 million from our core large-scale natural gas transmission and gathering and processing businesses, including new records for both gathering and contracted transmission capacity. But it also included strong performance from our Sequent gas marketing business, which dramatically overcame a perfect storm of severe winter weather impacts on our Wyoming businesses. Those Wyoming impacts included hits to both upstream and gathering and processing volumes as well as our Southwest Wyoming gas processing margins which were much lower from a surge in January shrink replacement gas price. Our adjusted EPS increased 37% for the quarter, continuing the strong growth we have had in EPS over the last many years. Available funds from operations, AFFO growth was even better than adjusted EBITDA at 22% year-over-year. Also, you see our dividend coverage based on AFFO was a very strong 2.65x on a dividend that grew 5.3% over the prior year. Our balance sheet continues to strengthen with debt to adjusted EBITDA now reaching 3.57x versus last year’s 3.81x. And that’s even after closing the trade, NorTex and MountainWest acquisitions and also repurchasing $83 million of shares since last year. On growth CapEx, you see an increase over first quarter last year primarily reflecting the progress we are making on some of our key growth projects, including Regional Energy Access and Louisiana Energy Gateway. So before we move to the next slide and dig a little deeper into our adjusted EBITDA results for the quarter, we will provide a few updates to our 2023 financial guidance. No change to our consolidated adjusted EBITDA guidance of $6.4 billion to $6.8 billion or any of our other consolidated financial performance metrics. Looking further into the year, our core transmission and gathering and processing businesses should see some additional growth from the first quarter level. For transmission in Gulf of Mexico, we will see some ramp from a full quarter of MountainWest Pipeline and some other smaller sequential improvements through the rest of the year that should allow for a strong finish to the year. In the Northeast, we are expecting a modest increase towards the end of the year from the first quarter EBITDA level, primarily from our higher margin liquids-rich systems. Overall though, we are not counting on a lot of additional growth in the Northeast from this $470 million first quarter level, which was up 12% over the prior year. In the West, we are expecting some modest increases through the remainder of the year from the $286 million first quarter level, especially reflecting improvement from some of the challenges we saw in the first quarter, which we will discuss further on the next slide. For the marketing business, we have had a strong overall start to 2023. And importantly, hitting the midpoint of our guidance doesn’t rely on any additional EBITDA from Sequent at this point. With respect to the upstream joint venture EBITDA guidance, it’s been a tough start to our Wyoming operation with the extremely difficult winter weather that significantly impacted producing volume and our drilling plans. So we see this business likely trending towards the lower half of the $230 million to $430 million guidance range. But to be clear, for our consolidated adjusted EBITDA, we are still focused on hitting at least the midpoint of our guidance range at $6.6 billion. We are increasing our growth CapEx by $200 million to reflect the acceleration of our largest Transco project, Regional Energy Access, which we hope to bring into partial service later this year, early partial in-service for regional energy access won’t have a huge impact on 2023 and is really just upside to our hitting the midpoint of our guidance for EBITDA. So, let’s turn to the next slide and take a little closer look at the first quarter results. Again, the first quarter matched our expectations for a very strong start to the year with 19% growth over the prior year. Walking now from last year’s $1.512 billion to this year’s record $1.795 billion, we start with our upstream joint venture operations that are included in our other segment, which were up only $3 million over last year. Our Haynesville upstream EBITDA was up about $32 million as there was really very little production in the first quarter of last year. However, the Haynesville increase was offset by lower Wamsutter results due primarily to the historically difficult winter weather we saw in Wyoming this year. In fact, we estimate overall weather-impacted volumes during the first quarter were probably about 3.5x what we normally expect. And of course that impact flowed through to our Wamsutter gathering and processing assets as well. Shifting now to our core business performance, our transmission in Gulf of Mexico business improved $31 million or 4% due primarily from the partial contribution from the MountainWest Pipeline acquisition, which closed on February 14 and a full quarter from the NorTex acquisition. Our Northeast Gathering and Processing business performed very well with a $52 million or 12% increase driven by $73 million increase in service revenue. This revenue increase was fueled by 7% increase in total volumes in the Northeast focused in our liquids-rich areas, where we tend to have higher per unit margins than our dry gas areas. And in the appendix, you will find a slide that compares our 7% volume growth to the overall basin growth of just under 2%. Shifting now to the West, which increased $26 million or 10%, benefiting from positive hedge results and a full quarter of the Trace acquisition, but the West was significantly unfavorably impacted by the severe Wyoming weather and January processing economics at our Opal Wyoming processing plants. Overall, gas processing margins were $44 million lower this year than last and that was largely a January phenomenon. All in, the West was about 3% short of our plan, although the winter weather impact was much worse than we had planned. And then you see the $165 million increase in our gas and NGL marketing business. And at our Analyst Day, we did point to a strong start to the year for this business due to the economics that we saw around our year end Sequent transportation and storage positions. Ultimately, the $231 million for gas marketing was driven by positive transportation margins across all regions and strong storage margins that benefited from the lower cost or market write-down we discussed in the fourth quarter review. So again, a strong start to 2023 with 19% growth in EBITDA, driven by core infrastructure business performance with strength from our marketing business that dramatically overcame weaker-than-expected results from the upstream joint ventures. And with that, I will turn it back to Alan.

Operator:

[Operator Instructions] Your first question comes from the line of Brian Reynolds from UBS. Your line is open.

John Porter:

Yes. Thanks, Brian. We certainly have seen that since we bought Sequent back in about 18 months ago or coming up on 2 years ago, Sequent has a great ability to capitalize on natural gas price volatility, but also doing that using a low-risk business model. I would say though that we are really not ready to take the $50 million to $70 million long-term run rate that we have talked about before up at this point. Some of these positions that they utilize are more short-term in nature, especially the storage positions. And again, we would emphasize that a big reason they have been able to do as well as they have has just been the historically high natural gas price volatility, especially what we saw last year through the summer months and also in the fourth quarter. So those are a couple of reasons that we would like to stick with the $50 million to $70 million long-term run-rate. However, as I mentioned in my commentary, I forecast – our current forecast does show that we do not need any additional EBITDA from Sequent this year to make the midpoint of our guidance. And as I also mentioned, the favorable results really did show in the first quarter how Sequent was able to counter the unfavorable results we saw in our gas processing margins and some of the other things that we saw in the Upstream and Wamsutter gathering and processing EBITDA.

Alan Armstrong:

Yes. Thanks, Brian. This is Alan. First of all, I think what we are seeing already, April numbers came out on power generation and power generation was already up about 2 Bcf a day on a previous 27 Bcf a day load for April of ‘22. So we are already seeing some pretty good pool based on price on natural gas in the power generation space. And I think we will continue if prices stay low like they are, I think we will continue to see that through the summer on the full side. So that’s a good thing for us just because obviously, the capacity demand will be important for us. I think on the – in terms of that impact on the G&P business, I think we’re certainly paying close attention to that. Many of our big producers are hedged out pretty well, and we’re seeing people continuing to produce through that. So don’t expect – we’re certainly not expecting growth on average across the space, to be clear, but we’re pretty fortunate to be in some of the lower-cost basins and with producers that have been managing this pretty well. One of the areas that we’re really seeing continued growth is in the rich gas and some of the condensate areas in the Marcellus and the Utica areas, and so we’re fortunate to be pretty well exposed to that area as well. So I would just say, as always, we have such a wide variety of exposure across so many different basins that will whatever the demand pool is on natural gas, our volumes will reflect that and really excited this quarter to see our Sequent team, it’s been a strategy of ours for our Sequent team to go out and provide market and preferentially to our gathering customers in places like the Marcellus because obviously, there is value for our gas moving over the top of other gas in the basin. And so certainly, our Sequent team has shown their ability in that area and we’re excited to see that. So I would just say we’re – I’d say on the macro side, it certainly see an oversupply situation. Supply grew almost 6 Bcf in first quarter of 23% versus first quarter of 22%. So supply side is certainly continuing to grow a lot faster than demand and obviously that means lower prices. But I do think we will see a pretty big response from power generation this summer as we’re already seeing here – as we already saw in April.

Operator:

Your next question comes from the line of Jeremy Tonet from JP Morgan. Your line is open.

Alan Armstrong:

Good morning, Jeremy.

Chad Zamarin:

Yes. Thanks, Jeremy. This is Chad Zamarin. We continue to advance our wellhead water strategy since our Analyst Day update. And I’ll start by saying you referenced the Sempra HOA. I mean we think very highly of the Sempra team and have continued to engage with Sempra following the non-binding HOA we announced last year. But we’ve also been evaluating a number of competing opportunities as well. We’ve been spending a lot of time with our producer customers as well as with international LNG buyers, and we’re seeing really positive strong interest in both producers wanting access to international prices and international LNG buyers wanting access to domestic producers so they can buy LNG from U.S. supplies at international prices. And so we think we provide a unique solution. We haven’t finalize the definitive agreement yet, but we continue to build confidence around our ability to add LNG as an extension of our natural gas value chain in a way it will provide for fixed margins for Williams while shifting that international price exposure to producers and LNG buyers. And so I would just say that we continue to prove up the strategy. We feel really good and feel like we’re making great positive strides. And I think we’d expect to finalize a definitive arrangement with Sempra or with an alternative LNG partner sometime here in the near-term 2023.

Michael Dunn:

Hey, good morning, Jeremy, this is Michael. Yes, I would just, first of all, I want to thank our project execution team for doing a tremendous job being prepared to start construction on that project. It’s a challenging permitting environment, especially in the Northeast right now, and the team designed this project so that it could be permitted and we really got through that process fairly quickly there. Ultimately, and the team was certainly prepared to the tree-clearing window that was closing very rapidly post FERC certificate issuance and really pleased that we got that tree-clearing done early, and we’ve actually fully mobilized contractors for the pipeline loop installations. So we do expect a partial in service by the fourth quarter of 2023. So there will be a contribution to 2023 EBITDA. We’re not predicting the actual in-service date of that yet, but it will be before year-end. And I do think that will translate to some opportunities in the gathering business as well upstream. The producers have been awaiting this additional capacity to be unlocked in the Northeast. And we are certainly pocketing those producer customers up there to be anticipating when this project will come online. But I do think it will provide additional value in ‘24 as well, and I think that’s really where we’re going to see the additional uplift on the gathering business, certainly not only on the Transco side. Really pleased with how it’s gone so far, and we will keep you updated as we progress with the construction through the summer.

Operator:

Your next question comes from the line of Marc Solecitto from Barclays. Your line is open.

John Porter:

Yes, Marc, I’ll take that on. Michael can add any color. I think break it down into a couple of different areas. One, we’ve talked quite a bit about the impact of the NGL margins, which is pretty clear. If you look at the analyst package on the appendix to the press release, NGL margins were $44 million lower year-over-year. So that’s a pretty good go by in terms of the impact there. Almost all of that decrease in NGL margins happened at the Opal processing plant and almost all of that was related to the historically high shrink cost that we had in January of this year where natural gas prices were in the $50 a dekatherm range. And since then, we’ve seen that come way back down into something much more normal like $2.50. As far as the rest of the impact, if you kind of look at the sum of what happened in the upstream JV part of the business at Wamsutter plus the Wamsutter gathering and processing impact. Some of those two were about $70 million lower than our planned expectations for the first quarter. So again, between those two, about a $70 million impact, yes, we saw – I think one of the things we looked at said that we saw probably about 12 Bcf of impacted volumes for the whole first quarter, whereas in a normal year, that might be a little bit more than 3 Bcf. So just very historic conditions out there and the recovery is ongoing. It’s – now we’ve transitioned to high rivers and muddy roads but the recovery is happening and volumes are being restored and margins are returning to a more normalized level. So expect quite a bit of improvement there when we get to the second quarter versus what we saw in the first quarter.

Alan Armstrong:

Yes. Thanks for that good question. I think really, if you break that down, the areas that are going to be driven. Obviously, anything that is heavy gas use is coming home. If we’re going to be – we are the major exporter and will be the growing larger exporter. It means we’ve got the lowest price natural gas around the world likely, and that will bring the industry here, like fertilizer business, obviously, is a big piece that been picking up pretty significantly from that, but a lot of other industries that are heavy natural gas users will continue to be domiciled here in the U.S. So that, I think, is fairly certain. I think in terms of how much that is, it will probably be pretty small in comparison to the LNG growth that we’re seeing. And it’s pretty impressive right now to look at the amount of NGL growth I think right now, there is about 23 Bcf of new expected on by 2032. And that’s up against a ‘22 number of about 10.9 Bcf a day. So, a lot of growth coming in that space. The other area, as I mentioned earlier, obviously, the power generation sector and for us, that’s kind of got two facets to it that I think sometimes the market misunderstands for us. First of all, certainly, when low gas prices are there, we will see that take out a lot of the baseload coal business that’s out there today. We’re already seeing that here in the shoulder, but we will certainly see it this summer. But in addition to that, from a Williams perspective, we sell the capacity. And so as you see more and more electrification occurring, it’s very clear that the utilities are going to be left with really no other alternative in gas-fired generation as a backup for that, and we are certainly seeing that in our discussions with our customers and a demand for that incremental capacity that’s available that we can uniquely provide into some of those markets. And so that demand for capacity as opposed to volume is a really key thing to note from a Williams perspective because we’re not all that concerned about the annual average demand for natural gas as much as we are the capacity that has to be provided to back up renewables. And as you study electrification, that is really going to fall to the benefit of natural gas-fired generation and particularly to the infrastructure, both on the transmission and the storage side that can support that. And obviously, we continue with our MountainWest acquisition and with our expansions on the Transco system, our conversion of Washington storage and our purchase of NorTex storage last year. We are all about being in a position to serve that business and serve it well.

Operator:

Your next question comes from the line of Praneeth Satish from Wells Fargo. Your line is open.

Alan Armstrong:

Yes. Well, I would just say where there is volatility, that’s where Sequent going to perform well and where there is basis dislocation that’s where they are going to perform because effectively, what we’re really monetizing with Sequent is we’re monetizing storage. So price movement from one period from a time-based period obviously drives value for us. as well as dislocation and basis differentials when we own the transportation between those locations. That’s really what drives value for Sequent. And so I would say that it’s pretty hard to forecast a period where we don’t see quite a bit of volatility in price as we’ve got a big growing demand for LNG looming on the horizon and people not being exactly certain when that’s going to be available. And certainly, the value of storage to serve those loads and to serve quick swing loads for renewables is definitely on the horizon. And I think we will continue to cause volatility both from a time spread and both from a basis spread perspective. And so we’re pretty excited about the way that Sequent will perform in that. But what it wouldn’t protect from is if we were sitting here with a completely flat curve at both prices far out in the future, that’s the environment that it wouldn’t provide us any protection and to be clear. But as long as we’ve got basis spread and we’ve got time spread and value there, that’s where the Sequent team is going to perform well.

Chad Zamarin:

Thanks. This is Chad. As of right now, that team is continuing to perform and performed exceptionally well. We’ve got great partnership with GeoSouthern. And right now, they are holding production based on the available midstream capacity. And as Alan mentioned, as you noted, the forward curve is constructive, so they intend to kind of keep that development pace going and we’re looking at kind of the gas macro coming into late ‘24, early ‘25 and seeing demand pick up. So I think there is a desire to want to be ready to make sure the volumes are there as the market continues to balance towards more demand. And so our expectation is that they’ll continue to keep pace with the midstream capacity. They work very closely. Again, the Sequent story, I mean we are working really hard to make sure they find good markets. And so we think also with the Louisiana Energy Gateway project and our ability to get the GeoSouthern volumes connected to really good markets that they’ll continue that growth that we’ve laid out.

Operator:

Your next question comes from the line of Gabe Moreen from Mizuho. Your line is open.

John Porter:

Thanks for the question, Gabe. Obviously, financial performance continues to be really strong for the company, and the balance sheet is in great shape. Regarding the buybacks, really no change to the returns-based approach that we’re taking on the share repurchases, very similar to what we discussed at Analyst Day, we’re really looking at all of our investment opportunities that we have in the company and seeing that our lowest expected returns on capital investment in the business are really associated with our regulated rate base investments, principally through our emissions reduction program, which we’ve talked about being at that 11%, 12% return range. Obviously, this year, since the beginning of the year, we’ve seen a pretty sharp decline in our valuation as natural gas prices dropped. And we saw our dividend yield expand to 6%, even while we continue to have a lot of confidence in our long-term 5% to 7% growth rate. So that looked like a pretty attractive investment opportunity relative to all of our options. So we took action to utilize some of that financial flexibility for share repurchase. And I think going forward, it will be a similar approach. We will just monitor conditions and weigh that investment opportunity up against the other investment opportunities that we have.

Gabe Moreen:

Got it. Thanks, Alan. Thanks, John. And maybe I could just ask a two-parter on growth projects. One is on the MountainWest opportunities that I think you alluded to, to the extent you can describe maybe some of those that are coming to fruition? And then second is low gas prices at all impacting, discussions with potential leg customers on that expansion or new projects?

Michael Dunn:

Yes. The LEG project in regard to the opportunity there, I think we still see an opportunity to have that project online later this fall. We are in the permitting process for the project today. And I don’t see any obstacles to being able to achieve in service that as we have expected to come online in the 2024 timeframe. Right away acquisitions occurring there as well, and we are seeing a lot of expectations there with our producer customers and bring that online and those are take-or-pay type contracts. And so very comfortable with where we are sitting today on that project.

Operator:

Thank you. Your next question comes from the line of Neal Dingmann from Truist Securities. Your line is open.

Alan Armstrong:

Yes. So, was that on our gathering contracts?

Michael Dunn:

Yes. So, we have a number of contracts that do have exposure to natural gas pricing. We have talked about those in the past, where some of those have direct NYMEX exposure like in the Barnett, some like more about midstream at the floor underneath those. And then we have some of the Haynesville wells that have exposure as natural gas prices ratchet up, where we have peers that we haven’t publicly stated what they are. But as natural gas prices do escalate, we have an opportunity to increase our fees on those gathering rates. So, I would say, for the most part, we are very comfortable with where we stand in regard to our guidance this year and the expectation for what those triggers are in regard to our gathering rates. And I will just also remind you that we do have a lot of fee escalation in those based on inflation in disease. And so many of those have kicked in over the last several years as well. And our team has done a really good job controlling our costs, and we feel really good about where those escalators are in relation to our cost escalation being able to cover those – any cost increases that we see. And a lot of those cost increases that we are seeing are in power generation, for example, and a lot of those are pass-throughs to our customers as well. So, we don’t have exposure to that. But all-in-all, we are very comfortable with where our G&P rates are today in regard to the low natural gas prices.

Jake Nivasch:

Perfect. Thank you.

Tristan Richardson:

Hey guys. This is Tristan with Scotiabank. Can you hear me okay?

Tristan Richardson:

Appreciate it. Appreciate your comments, Alan, on Gulf of Mexico and bringing Taggart online, but maybe kind of curious just a general update on the progress of sort of the big five coming online in ‘24, just general progress and an update there would be great.

Michael Dunn:

Yes, sure, I will take that. No real change from what you have seen in our published materials in regarding our projects. We have made really good progress on the Whale projects, in the Western Gulf of Mexico, we have the offshore pipeline that was installed last fall, and we just recently installed the deck modifications on the platform that brings the gas and oil to shore there, and that was just done last week. So, that work is progressing with an outage there as we speak. And all-in-all, we feel very good about that work. The Markham processing plant modifications are underway as well. So, we will be well in front of when the producers are expected to come online in 2024 for that project. The Shenandoah project in our Discovery system is also going very well. A lot of the offshore work by the producers is underway. And our onshore work has been fully permitted and that we are working under the construction projects also. And so nothing has changed on the timing of those. We hope that producers will accelerate those, and we will be ready for that if they choose to do so. It’s really up to their schedules right now as to when they bring those online. But like for the Whale project, they have wanted us done well in advance of their offshore activities. And so we are prepared to go early if they choose to do so. And that’s where we stand today on those. But really good progress on the non-CapEx tie-backs and the opportunities that we have had out there also.

Tristan Richardson:

Okay. Thanks Alan. And then maybe just on LEG. I appreciate the updates there. But maybe curious on how things are progressing on the carbon side of that project. Do we need to be in sort of a primacy in Class 6 world for that component of LEG to go forward, or maybe just an update on what you are seeing on that?

Tristan Richardson:

Great. Thanks Chad. Appreciate it guys. Thank you.

Spiro Dounis:

Thanks operator. Good morning team. First question, going to upstream actually, it sounds like not an urgent need to monetize those assets, of course. But as I recall, you have been pretty close to an asset sales in the last year. So, just curious where does that process sit right now? And is that forward curve strong enough to maybe incent some buyers to come in here at attractive levels for you?

Spiro Dounis:

Got it. That’s helpful color. Thanks for that Alan. Second one, just wanted to come back to the guidance quickly for a second. I think back at the Investor Day, you have mentioned that the guidance contemplated a producer slowdown just given where you saw the natural gas price at the time and it looks like, to some degree, that’s been proving out. We have seen a handful of announcements now on some slowing of activity, I guess I am just curious, compared to what you were thinking in February, how does that kind of track to your expectations?

Spiro Dounis:

Perfect. Helpful color guys. Thank you.

Sunil Sibal:

Yes. Hi. Good morning everybody. So, my first question was related to some recent comments from the administration, especially with regard to gas infrastructure. I was just curious, is that something that you also picked up on based on your discussions with the administration. And then is there a specific opportunity for Williams to capitalize on that note?

Sunil Sibal:

Got it. And then on the LNG marketing strategy, so we will kind of stay tuned to updates coming up on that. But I was just curious, is that marketing strategy more driven by supply push currently, or is it more of a demand pull in the international markets?

Michael Dunn:

Yes. If I could add to that, this is Michael. The opportunities that we are looking at also involve some pretty significant FERC regulated fee-based pipeline opportunities for the infrastructure to be built there well beyond what we are thinking about with the LEG project. So, we are certainly looking at the opportunities to build FERC regulated transmission projects associated with this wellhead water strategy.

Chad Zamarin:

Yes. I would say that we are not going to take large open mismatch positions. There may be some modest mismatch across the portfolio of LNG transactions. But our goal is going to be to not have a lot of speculative open positions, again kind of offer a unique product to the market and our goal would be to, for the most part, de-risk the term of those commitments. And if we do take any lesser term on a commitment to make sure that the margin that we are capturing is more than adequate to support that. But for the most part, we are targeting significant coverage and matching of the terms across the portfolio.

Operator:

Your final question comes from the line of Jean Ann Salisbury from Bernstein. Your line is open.

Michael Dunn:

Yes. Jean Ann, this is Michael. I would say those are more of the latter right now. These are fairly low CapEx compression with some small lubing opportunities with really healthy returns on those projects. Anything that would be associated with NBP completion would be a much more substantial capital-intensive project opportunity that we are certainly looking at with customers. But at this time, we haven’t announced anything in that regard. But there definitely are opportunities that NBP is successful and the takeaway from Transco will ultimately be built.

Jean Ann Salisbury:

Great. Thanks a lot.

Alan Armstrong:

Great. Thank you. Well, we are really as a team, I tell you, we are really excited to deliver the quarter that we just delivered, particularly within commodity cycle that we are in and really excited about how we are set up for the future and some of the great accomplishments that team delivered this quarter as well. So, we look forward to rewarding our shareholders with more growth in the future and are very well positioned for that. So, thank you for joining us today and look forward to talking to you in the future.

Danilo Juvane:

Thanks, Gina, and good morning, everyone. Thank you for joining us and for your interest in The Williams Company. Yesterday afternoon, we released our earnings press release and the presentation that are President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, will speak to you this morning. Also joining us on the call today are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks, and you should review it. Also included in our presentation materials are non-GAAP measures that we reconcile to generally accepted accounting, and these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

John Porter :

Thanks, Alan. Starting here on Slide 2 with a summary of our year-over-year financial performance. Overall, 2022 financial performance continues to be quite strong. Beginning with adjusted EBITDA, we saw a 15% year-over-year increase for the third quarter and a 12% increase for the first nine months of '22 versus '21. As we'll see on the next couple of slides, our adjusted EBITDA growth has been led by our core large-scale Natural Gas Transmission, and Gathering and Processing businesses, complemented nicely by growth in our upstream joint ventures. Our adjusted EPS increased just over 37% for the quarter and 34% year-to-date. Available funds from operations, AFFO, which is basically our cash flow from operations less working capital fluctuation, the non-controlling interest cash flows grew in line or better than adjusted EBITDA at 15% year-over-year for the quarter or 18% for the nine-month period. Also, you see our dividend coverage on this page based on AFFO was 2.4x for third quarter and 2.29x year-to-date. Our debt to adjusted EBITDA metric continues to improve based on our strong growth in adjusted EBITDA and our capital investment discipline, now reaching 3.68x versus last year's 4.04x. So now let's move to the next slide and dig a little deeper into our adjusted EBITDA results for the quarter. Again, the third quarter built nicely on the strong start we've seen this year with 15% growth reflecting the combined effect of the performance of our core business and upside from our upstream joint ventures. Walking now from last year's $1.420 billion to this year's $1.637 billion, we start with our upstream joint venture operations that are included in our Other segment, which were up $60 million. Since our first new production in the Haynesville came online in April of this year, we've seen a rapid ramp in volumes that will continue through the remainder of the year. As Alan mentioned, the strategic purpose of our upstream joint ventures is to fuel growth in our core related gathering assets, and that's certainly what we see happening in 2022. Shifting now to our core business performance. Our Transmission & Gulf of Mexico business improved $41 million or 6% due to improved contributions from both Transco and our Gulf of Mexico businesses. Transco saw higher revenues, largely from the Leidy South expansion project, which came online in phases last year. Gulf of Mexico was significantly higher in '22, due in part to the lack of hurricane-related impacts that occurred in 2021. Operating and maintenance costs were higher, driven in part by higher maintenance activities but we are tracking very close to plan through the first nine months of the year. Our Northeast G&P business increased $22 million or 5%, driven by top line Gathering and Processing revenue growth on slightly lower volumes. Gathering and Processing rate growth was supported by a combination of factors, including higher commodity-based rates, annual fee escalations and other expansion-related fee increases that more than offset the lower cost of service rates at our Bradford franchise. Overall, Northeast volumes were 10.8 Bcf per day and roughly in line with our current forecast for total 3Q volumes. We continue to expect an increase from this volume level for the fourth quarter. But as we've mentioned in past calls, our '22 plan for the Northeast has always been higher EBITDA versus 2021 on pretty flat volume growth. However, as Alan mentioned, we remain well positioned to resume stronger volume and EBITDA growth in the Northeast in 2023, driven by several expansion and optimization projects. Shifting now to the West, which saw another impressive quarter of year-over-year growth, up $80 million or 31% over 2021. I should mention that $27 million of the $80 million was attributed to our Trace Midstream acquisition, which closed on April 29 this year. So even without Trace, the West still increased $53 million or 21%. In the West, we continue to see upside from our commodity price exposed rates, especially in the Barnett and Haynesville as well as substantially higher volumes in the Haynesville that drove a 12% overall increase in volumes for the West and that's excluding the Trace acquisition. Next, we saw a $4 million or 12% increase for our Gas & NGL Marketing Services business. This increase was despite taking a $54 million lower of cost or market adjustment to our gas and NGL inventories in September of this year. Generally speaking, most of this adjustment, which was associated with our gas and storage will result in higher margins when those products are sold out of inventory late this year or early next year. So again, another strong quarter with 15% growth in EBITDA, driven by core business performance and upside in our upstream joint venture operations. Let's move to Slide 4 and look at the year-to-date comparison. Through the first nine months of '22, we've now generated 12% growth in adjusted EBITDA over 2021, three strong consecutive quarters for this year. So stepping now from last year's $4.152 billion to this year's $4.644 billion, starting with the $77 million of first quarter 2021 winter storm benefits that we're showing here in gray, and then moving to the $182 million contribution from our Midstream operations which were Wamsutter related in the first quarter of '22, and then begin to have a more significant Haynesville component in the second and third quarters. Our Transmission & Gulf of Mexico business has seen 4% growth year-to-date, driven by Transco's Leidy South expansion project and strong first quarter '22 seasonal revenues and also higher Gulf of Mexico results due to less hurricane-related impacts in '22 versus '21, partially offset by higher operating and maintenance costs. The Northeast G&P business has now seen 6% growth year-to-date, driven by higher rates on overall flat volumes, as previously discussed. The West has seen an impressive 27% growth year-to-date, driven by higher commodity base rates, but also a strong 11% overall volume growth, excluding the Trace acquisition. Finally, our Gas & NGL Marketing Services segment is up $32 million, driven by favorable commodity margins as well as the new contributions from the Sequent acquisition that closed on July 1, 2021, and the year-to-date comparison was also unfavorably impacted by lower cost or market adjustments on inventories as discussed in the third quarter comparison, which as we discussed, should result in higher margins in the future. So an impressive $491 million or 12% increase to land us with over $4.6 billion of adjusted EBITDA through the first nine months of the year. Before I turn it back over to Alan, I'll offer a few thoughts for full year 2022 financial guidance. As we previously announced, based on strong third quarter performance and expectations for the fourth quarter, we anticipate full year adjusted EBITDA will be near the high end of our previously announced guidance range of $6.1 billion to $6.4 billion, which implies a strong fourth quarter. We see multiple contributors to this expected strong finish to the year, including continued growth in our upstream joint ventures, but also growth across our other business segments versus our third quarter results. One other note regarding the third quarter, you probably noticed in our 10-Q that we did initiate share repurchases in September. As we discussed on our second quarter call, we stand ready to take action on share repurchases, and we see a pullback in our valuation, and that's what we did in September. Our share buyback principles center around a returns-based approach considering our current equity yield plus a level of expected growth in the business. We are more confident than ever in the long-term growth of our business, and so we remain ready to purchase additional shares as an important element of our capital allocation strategy. Debt financing costs have also been topical lately with the sharp rise we've seen in borrowing costs. We've included some helpful information on our well-positioned debt portfolio in the appendix, but I'll briefly touch on a few key facts. First off, we have an entirely fixed rate debt portfolio with an average rate of 4.78%, and a weighted average maturity of 12.2 years. Second, following our well-timed August debt issuance and subsequent call of $850 million of 2023 notes recently in October, we now only have $600 million of maturities in 2023. And finally, we will continue to enjoy excellent financial flexibility with our $3.75 billion credit facility. So again, with our expectations to finish 2022 near the high end of our adjusted EBITDA guidance, this would amount to over 13.5% growth versus 2021 and a four-year CAGR of about 8%, driven by continued growth in our core business as well as contributions from our Trace acquisition and upstream JV operations. So with that, I'll pass it back to Alan for closing remarks. Alan?

Operator:

[Operator Instructions] Our first question will come from the line of Jeremy Tonet with JPMorgan.

Chad Zamarin :

Yes. Thanks, Jeremy. This is Chad. Yes, the IRA and the increase in 45Q credit is certainly a benefit that helps that project move forward. The scope of that project is alongside our Louisiana Energy Gateway project as we're gathering large volumes in the Haynesville. We'll be taking the CO2 that today is invented in the basin into the pipeline, and we'll also be gathering CO2 from third parties and moving that CO2 to the Southern end of the Louisiana Energy Gateway gathering project. And at that location, we're going to install treating facilities that will remove the CO2 and transport it to a sequestration site so that it can be permanently stored underground. We see somewhere around the potential for 2 million tons of annual CO2 to be captured and sequestered. And we think that could increase over time as we continue to further develop that project. So we feel really good about it, and we're focused on bringing that online alongside our Lake project, which could be in service as early as Q4 of '24.

Alan Armstrong :

Yes, Jeremy, I just -- let me be clear on that. First of all, I think there's been a lot of confusion out there in the market on the forms of those contracts. We expect production net -- our net interest production to continue to grow in '23. And so we have been very pleased with GeoSouthern's efforts out there. They've been a great operator and they've really been hitting it out of the park, so to speak, in their efforts and the performance on wells, both on the cost side as well as delivery side. So we're really excited about their activities out there. So we do -- just to be clear, we do expect our net interest production to continue to grow into '23. And so the people have been talking about a decline relative to the reversion. Our interest in the undeveloped acreage declines, but not our interest in the existing flow of production. And in fact, the nice thing about that is our capital obligations really fall back really hard in '23 after that reversion occurred because we won't be continuing to have to invest in drilling operations there. So -- but in terms of looking for -- to sell the asset, we certainly -- that is our long-term objective and continues to be. And we think the acreage is certainly proving itself up to exceed it. I would tell you, though, it's got a long ways to go from where it is today in terms of total volume growth in that area. In fact, really just starting to scratch the surface of that inventory in the area. So yes, we certainly have our eyes and ears open, but no, we are not getting near the peak of the volumes out there at all. And so it's really playing out on its exact we like we intended accept that we've had this nice, big upside of pricing here in the current environment. And the volumes this year have been -- are outperforming where we thought they would be. So great news really kind of all the way around there in terms of upside, and it's going to drive a lot of free cash flow into '23 and '24.

Alan Armstrong :

No. I would just say, we've got -- there's a lot more room to grow out there than what people are expecting, I think. I think we continue to be impressed by other is informing us on in terms of kind of well beyond the current reduction level. So I would just say we're not waiting, if you will, necessarily. We just want to be assured that the production growth will continue on the pace kind of if we're not the owner. And I think certainly, the alignment we've had with GeoSouthern out there has been productive for both of us. But no, we're not waiting on any particular volume number. We think the evidence is pretty clear in terms of the performance out there at this point. So we think the viability of that acreage has been pretty well proven up already just in terms of the performance of GeoSouthern channel already.

Praneeth Satish :

In light of the NorTex acquisition, I was just wondering if you could elaborate on the benefits of gas storage right now. Do you think storage has become more valuable? Do you think spreads could widen out? How does this fit with Sequent? And then finally, do you envision building out more gas storage assets organically or doing more acquisitions in this space?

Praneeth Satish :

Great. And just switching gears. If we -- if I look at the financial metrics this year, the leverage is good and EBITDA is on pace to grow 13% or 14%. But on the capital return side, the dividend is only up 4%, and there's been some buybacks, but it's been fairly modest. So I guess my question is, is the strong performance this year influence how you look at capital return heading into 2023?

Operator:

Your next question will come from the line of Chase Mulvehill with Bank of America.

Alan Armstrong :

Yes, great question. I think you've laid that out pretty well actually. I would say the other thing that we didn't enjoy this year that we will enjoy next year is the investments that we've been putting into the Wamsutter JV this year. I mentioned, we have -- we're continuing the drilling program, but we are just now starting the completions effort out there. And so the benefit of that those drilling capital we've been spending up there this year will really start to play out in '23 as well. So that's a key issue. As I mentioned, the Eagle Ford, we're seeing some pretty rapid development going on in the rich gas that will see the MVC out there. So that's attractive. In terms of the headwinds, I certainly think pricing is a consideration, but I think it's also important to realize the amount of hedges that we had on this year that kept us from enjoying extremely high gas prices this year. And so I think if you look year-to-year, they're probably not likely going to be that big a spread. I would say we're strip. So that's probably the primary headwind. But from what we're seeing right now, that is going to be dramatically overcome by volumes in the E&P space. And so yes, we could see lower price, but our volumes, I think, will surprise people to the upside next year.

Alan Armstrong :

Yes. I would just say we continue to be surprised. I would say that was probably, as we mentioned earlier in the year, probably our biggest surprise has been the resilience of gas demand in the face of higher price. And I think what we learned was that the utilities and the power generators are not really able to flip back to coal for a number of reasons. One, they don't have the long-term contracts, a lot of those expired. And two, obviously, the price of coal has come up right alongside gas. And so we just did not see the flip back to coal-fired generation, we would have expected at this kind of pricing environment. Obviously, I think it's -- what you're seeing is a result of the utilities. And I don't think this is going to end anytime soon, where as renewables come on, the backup for that is going to be natural gas, and it's going to continue to take coal-fired generation out of the space and we're going to continue to see increases. So if you're listening to the rhetoric in the market and in the media, you would think that gas volumes were going to decline dramatically, if you saw the RFPs for new services coming in our door, you would think otherwise. And so I think what we are seeing is continued strong demand from gas-fired generation from the utilities, particularly in the Mid-Atlantic and the Southeast. So we're -- we remain bullish not because of rhetoric, but because of what we're seeing for request for long-term services coming in the door.

Gabriel Moreen :

Maybe if I could ask another question about '23 and just talking about how to frame CapEx. There's clearly some projects finishing up some bigger ones like Regional Energy Access and legs that are out there where maybe the spend gets spread over '23, '24. So I'm just wondering how to think about growth CapEx within the context of what it was this year and some of these longer-term projects?

Gabriel Moreen :

And this might be another one for you. But in the NWP rate case, it seems like you achieved sort of a modernization rider or there's some language about that. Can you talk about that and whether that's going to be significant and also whether that can be a precedent for Transco in the upcoming rate case?

Gabriel Moreen :

Great. And maybe if I could squeeze just a quick last one. It seems like you got a ruling in the energy transfer litigation, they're appealing. Is there any timing as far as how long that appeal may take to play out?

Operator:

Your next question will come from the line of Brian Reynolds with UBS.

Micheal Dunn :

Yes. Sure, this is Micheal. As I indicated, we think it's going to be about $1.2 billion, very similar to what we see this year on average going forward. But as I've talked about on previous calls, we do have some lumpiness anticipated there when these larger projects start to ramp up construction, retail energy access. We'll be ramping up construction next year. The Lake project will also be starting construction next year and then the Whale project in the Gulf of Mexico, will be in some pretty significant construction activities as well next year, although that has started this year. So as always, it will be lumpy, but we're very focused on being efficient in regard to our growth capital. So I would expect you would see a $1.2 billion to $1.3 billion average CapEx on our growth side for the foreseeable future.

Alan Armstrong :

Yes. Thank you. Well, we do have some favorable hedges on right now for '23. I think we've got around 15% or so for the year that's on right now. And we'll continue to look at that opportunistically. I would tell you that it's really nice having our Sequent team that is joined at the hip when it comes to making those decisions and having a real vantage point on the market. And what they're seeing as well. So I would just say we will continue to be somewhat opportunistic about that, but we certainly will continue -- just like we did this year, we'll continue to take on hedges as we see fit. But I would say we don't have any particular formula or a requirement for that. It's simply a way of when we see opportunities in the market and we see things flare up in the market, we'll hedge into that. So I would say it's fairly opportunistic, but with no particular requirement for a minimum level of hedges to be put on.

Alan Armstrong :

I'm sorry, I didn't quite follow that last part.

Alan Armstrong:

Yes. I mean, I would just say it's very dependent on what the markets do versus how we're seeing the fundamentals looking forward. The good news is we have such a good read on both what's going on in production because we gather in 15 different basins. So we have a very good read about what's going on in production as well as we see a good read from the markets as well that we use that to inform our fundamentals. And if we see the pricing obviously get fair relative to those fundamentals, then we will hedge. So again, I don't -- I wouldn't put a particular percentage on it as much as it is us looking at the fundamentals versus the pricing in the forward market.

Alan Armstrong :

Yes, that's a really good point that some of our reluctance to hedge at the beginning of '22 was based on us not wanting to hedge until we actually saw that reduction flowing given the volatility in the markets and certainly didn't want to get caught short in an upswing in the market. So next year, we'll have less of that. In the Haynesville, we'll have less of that volume growth risk, not so much in the Wamsutter.

Sunil Sibal :

I just wanted to go back to the opening comments regarding 5% to 7% EBITDA growth. So is that kind of the run rate we can assume based on your asset base now for the next few years?

Sunil Sibal :

Okay. And then regards to the Eagle Ford, I think you mentioned you're seeing some activity pick up there. I was curious what kind of gas or NGL prices kind of support this uptick in activity? And do you anticipate this activity uptick to kind of go into 2023 and further out?

Operator:

Our final question will come from the line of John Mackay with Goldman Sachs.

Micheal Dunn :

Sure. Thanks for the question. This is Micheal again. I would say we're very well positioned there with our gathering systems being connected to about nine different outlet pipelines out of the basin and having Sequent alongside us evaluating those takeaway opportunities has been very helpful. I believe they were well in front of the -- any anticipated constraints out there in front of the market and really went out and acquired some capacity out of the basin that made sure that not only our customers' volumes could blow, but our partnership upstream volumes could flow as well. So we feel very comfortable about our position in getting our gas out of the basin as well as our customers' gas out of there. We helped a lot of our customers make sure that they had opportunities to move their gas out of the basin based on what we were seeing with Sequent. So we feel really good about that. We're certainly working to get the Lake project up and running as fast as possible to help make sure that none of those constraints arise for our customers or our partnership.

Micheal Dunn :

Yes, Micheal once again answering this question. We are awaiting the FERC 7(c) certificate. We would expect to have that before the end of the year. The final EIS was issued in July, just as a reminder, that was a very favorable EIS for the project. The other remaining outstanding permits are the air permit. This is a Title V modification for Section 505 in New Jersey. Went through the whole public comment process, and this is a great opportunity for us to once again deploy our emissions reduction program here. We take off some existing compression and replace it with a much better emissions profile. So very favorably received by the state. And certainly, we saw some very positive comments there in the public comment meetings, overwhelming support for that. So we expect that air permit by the end of this year as well. And then finally, the core engineers will issue a 404 permit. This is a water quality permit. We would expect that probably in the first quarter of '23, but it could come as early as the fourth quarter here in '22. We've already had our 401 water certification in the State of Pennsylvania that's been in hand for a number of months now, and no technical issues remaining on the 404 permit just waiting for the process to play out. So those are the 3 outstanding things we're waiting on Regional Energy Access for right now. And just as a reminder, we positioned this project very well to avoid any controversial permits and certainly position that air permit in New Jersey to be favorably received with deployment of new compression there to take off some old vintage reciprocating compression.

Alan Armstrong :

Okay. Well, thank you all very much for the great questions and appreciate your continued interest in the company. We're very excited about the way the business is running right now, and we're extremely well positioned for growth in '23 as we discussed, and we look forward to talking to you at our 4Q earnings call and laying out in more detail what '23 looks like. So thanks again for joining us this morning.

Danilo Juvane:

Thanks, Joanne, and good morning, everyone. Thank you for joining us and for your interest in the Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks, and you should review it. Also included in our presentation materials are non-GAAP measures that we reconciled to Generally Accepted Accounting Principles. And these reconciliation schedules appear at the back of today's presentation material. So with that, I'll turn it over to Alan Armstrong.

John Porter:

Thanks, Alan. Starting here on Slide 1 with a summary of our year-over-year financial performance. Overall, 2022 financial performance continues to be quite strong. Beginning with EBITDA, we saw a 14% year-over-year increase for the second quarter and a 10% increase for the first half of '22 versus the first half of '21. As we'll see on the next couple of slides, our EBITDA growth has been led by our core large-scale natural gas Transmission, and Gathering and Processing businesses complemented nicely by growth in our upstream joint ventures. Our adjusted EPS increased 48% for the quarter and 29% year-to-date. Available funds from operations, AFFO, grew more than EBITDA, continuing the trend of strong growth in this measure, up 23% year-over-year for the quarter or 19% year-to-date. Also, you see our dividend coverage on this page based on AFFO was 2.19x for second quarter and slightly better at 2.24x year-to-date. Our debt-to-adjusted EBITDA metric continues to improve based on our strong growth in EBITDA and our capital investment discipline now reaching 3.82x versus last year's 4.13x. So now let's move to the next slide and dig a little deeper into our EBITDA results for the quarter. Again, the second quarter built nicely on the strong start we've seen this year with 14% growth, reflecting the combined effect of the performance of our core business and upside from our upstream joint ventures. Walking now from last year's $1.317 billion to this year's $1.496 billion, we start with our upstream joint venture operations included in our Other segment, which were up $66 million. I will point out that we've added a new page to our analyst package for this segment. And in that supplemental information, we've included our net upstream sales volumes, which were just under 200 million cubic feet a day for the Haynesville and Wamsutter properties for the second quarter of '22. Since our first new production in the Haynesville came online in April of this year, we've seen a rapid ramp in volumes that will continue through the remainder of the year. Shifting now to our core business performance. Our Transmission & Gulf of Mexico business improved $4 million, primarily at Transco and largely from the Leidy South expansion project, which came online in phases last year. Operating and maintenance costs were higher, driven in part by an acceleration in maintenance work during the second quarter of this year. Overall, Transmission & Gulf of Mexico's $652 million of adjusted EBITDA was just over our business plan for this segment for the second quarter. Our Northeast G&P business increased $41 million or 10%, driven by top line Gathering and Processing revenue growth on slightly higher volumes. G&P rate growth was supported by a combination of factors, including higher commodity-based rates, annual fee escalations and other expansion-related fee increases that more than offset the lower cost of service rates that we have in our Bradford franchise. We saw an expected sequential increase in Northeast volumes for the second quarter of 2022 versus the first quarter, and we expect continued quarterly increases for volumes for the remainder of the year. But ultimately, our plan for the Northeast in '22 continues to see higher EBITDA versus 2021 on pretty flat volume growth. However, we remain well positioned to resume stronger volume and EBITDA growth in the Northeast in 2023, driven by several expansion and optimization projects underway that Alan will discuss in more detail. Shifting now to the West, which saw an impressive $73 million or 33% improvement over 2021 and I'll mention that $20 million of that $73 million was attributed to our Trace Midstream acquisition, which closed on April 29. So even without Trace, the West still increased $53 million or 24%. In the West, we continue to see upside from our commodity price exposed rates, especially in the Barnett and Haynesville, as well as substantially higher volumes in the Haynesville that drove an 11% overall increase in volumes for the West, excluding the Trace acquisition. Also in the West, we see a strong quarter-over-quarter volume growth trajectory throughout the second half of the year, driven primarily by the Haynesville. Next, we saw a slight decrease for our Gas & NGL Marketing Services business as was expected in our business plan. And as a reminder, the first quarter of each year is typically when this segment will create the majority of its EBITDA. Overall, our Marketing Services business is extremely well positioned to take advantage of the recent natural gas price and location volatility we've seen in July. And so we expect them to exceed the high end of the $50 million to $70 million annual adjusted EBITDA contribution we discussed last quarter. So again, another strong quarter with 14% growth in EBITDA, driven by core business performance and upside in our upstream joint venture operations. Let's move to Slide 3 and take a look at the year-to-date comparison. So through the first six months of 2022, we've now generated 10% growth in adjusted EBITDA over '21 or 13% if you exclude the unusual first quarter 2021 winter storm benefits. So that's two strong quarters to start the year, so stepping now from last year's $2.732 billion to this year's just over $3 billion. And you start with the $77 million of those first quarter '21 winter storm benefits, which we've isolated here in gray, and then moving to the $122 million contribution from our upstream operations which, again, were Wamsutter related in the first quarter of '22 and then began to have a more significant Haynesville component in the second quarter, as discussed on Slide 2. Our Transmission & Gulf of Mexico business has seen 3% growth year-to-date, driven by Transco's Leidy South expansion project and strong first quarter '22 seasonal revenues with again some acceleration of maintenance costs into the second quarter of '22. The Northeast G&P business has now seen 7% growth year-to-date driven by higher rates on overall flat volumes as discussed on the previous slide. The West has seen an impressive 25% growth year-to-date, driven by higher commodity base rates but also a strong 11% overall volume growth, excluding the Trace acquisition. Finally, our Gas & NGL Marketing Services segment is up $28 million, driven by favorable commodity margins as well as the new contributions from the Sequent acquisition that closed on July 1 of last year. So an impressive $275 million or 10% increase to land us with just over $3 billion of adjusted EBITDA through the first six months of the year, and we expect things to improve from here for the remainder of the year. So let's turn the page and take a look at our current thoughts for full year 2022 financial guidance. We are once again pleased to share a substantial improvement in our 2022 financial guidance, making this the second increase since our initial guidance in February of this year. I won't go through each of these metrics, but will offer some commentary on the most pivotal numbers. So let's start with adjusted EBITDA, where our midpoint is increasing another $200 million from our last guidance increase moving from $6.05 billion to $6.25 billion. This second substantial raise in EBITDA guidance is grounded in our continued confidence in the growth of our core business and represents a nearly 8% increase from our initial guidance given in February. As we look to the second half of the year, we expect higher EBITDA than the first half for all of our segments, except perhaps the marketing business, and with an overall pick-up in sequential EBITDA growth for the fourth quarter over the third quarter. Although it's less certain, our Gas & NGL Marketing business could also match or exceed their first half performance during the last six months of the year, which is a bit unusual for this business. Their storage and transportation assets and trading capabilities are very well suited for the volatility we are seeing in this natural gas markets. Continuing on with the other segments, we expect Transmission & Gulf of Mexico should finish the year strong with fourth quarter numbers more like their first quarter numbers. And we continue to expect growing quarterly EBITDA and volumes from our West and Northeast segments with some level of acceleration through the latter part of the year. With respect to our upstream operations, we are encouraged by the results we've seen thus far in 2022. In the appendix, you'll see that we're guiding to fourth quarter '22 gross production of approximately 250 million cubic feet per day for the Wamsutter operation and we have increased our expectations for Haynesville to an estimated fourth quarter '22 gross production rate of about 400 million cubic feet per day. Our appendix slides also provide information about the specific hedges we've currently placed against our forecasted net production volumes. No change to our CapEx assumptions from our previous guidance update in May on our first quarter earnings call, which had increase from the February guidance only to reflect the Trace acquisition capital spending. You see that our debt-to-adjusted EBITDA is now expected to be about 3.6x at midpoint. The remainder of the guidance items either changed in relation to the change in EBITDA just discussed or remain unchanged. So again, a second substantial increase in EBITDA guidance representing an almost 8% increase in our midpoint from our initial guidance provided in February of this year, driven by continued growth in our core business as well as contributions from our Trace acquisition and improved expectations for our upstream JV operations. So with that, I'll pass it back to Alan to review our key investor focus areas. Alan?

Operator:

[Operator Instructions] Our first question comes from Chase Mulvehill from Bank of America.

Alan Armstrong:

Yes. Thank you. Great question. Well, first of all, the actual language for that proposed bill is not out. So it's kind of hard to comment on. But I would say that we've been working hard on our government affairs front and really the whole executive team in trying to influence the policy and the legislation that would come out on that. So we're hopeful that, that will be very meaningful. And if it does, I would think that it would try to address the situation where we've had states abusing the 401 water quality certificate that are blocked projects. And that certainly would open up some opportunities for us as we've had some projects blocked on that basis. So I would say we're optimistic, but a lot can happen in the world of politics and we're just not really certain exactly how that bill will come out at this point. But relative to the Haynesville, the Permian and the Marcellus, certainly, the Marcellus has been the basin that has been has decades of low-cost gas as well. But really, if we're going to get up on planes, and be a large exporter of natural gas, we're going to need the Marcellus for the long term because that is where a lot of our very low cost reserves are impacted basin by that will be the Marcellus because things like in Louisiana, for instance, that infrastructure, a lot of that is being expanded within the state. And it is up against some of those same challenges and certainly more supported politics in those areas. So we are very helpful. We think the Marcellus and the Utica both would benefit significantly from the kind of permitting reform that we're looking for.

Alan Armstrong :

Yes. We do have some pretty exciting projects. I'll let Micheal Dunn talk about some of those that will unlock some of that capacity in the area.

Operator:

Our next question comes from Marc Solecitto from Barclays.

Alan Armstrong :

Yes, we're not going to provide a whole lot of detail on that, just because it kind of becomes an endless thread to pull on from a pricing standpoint. But I would just say that there is upside at the current strip, there is upside in our -- against our midpoint, and that would push us up closer to the high end of the range if we were to see the current strip hold on natural gas. Not -- we don’t update our oil side so much. So there is little bit of impact to both NGLs and oil that obviously would be down a little bit from previous expectations.

Micheal Dunn :

Sure. This is Michael. I'll take that. So in the Transmission Gulf of Mexico business, we did see some cost increases there, and this was primarily driven by maintenance activities that we accelerated into the second quarter. We did anticipate some significant volume demand on the Transco system and seeing that expectation out there, we did accelerate some work to get that out of the way before the summer air conditioning loads on the power generation side. And so we accelerated that work. We also had some unforeseen integrity work that we undertook in the second quarter and we obviously didn't anticipate that, but that impacted our expenses there. I would just say, in rounding that out, though, we did exceed our EBITDA expectations and our plan for the Transmission Gulf of Mexico business in the quarter and year-to-date. So those expenses didn't impact our planned numbers and our expectations there. And in the Northeast, a very similar story there. We're just working on various maintenance overhauls and things of that nature in the second quarter. So costs are up slightly there, some of that’s driven by activity that we've expected to do in the second quarter. Really nothing unforeseen there against our budget though, I would say.

Jean Ann Salisbury:

It seems like Mountain Valley Pipeline could actually happen. There's been soft start before, but it may actually happen this time. Would that starting up have any material impact on your EBITDA?

Jean Ann Salisbury:

And then how large of an operational impact, if any, could this EPA turbine emissions will create for Williams? Can you give some color on how you see the way forward from here?

Operator:

Our next question comes from Praneeth Satish from Wells Fargo.

John Porter :

Thanks, Puneet. This is John Porter, I will take that. Yes, so relative to capital allocation, I might just sort of restate our current priorities and guidelines remain unchanged with the focus on our balance sheet strength and our growing dividend with very strong coverage, our strategic organic investments, including investments in modernizing our regulated assets and making disciplined new energy investments. And beyond these priorities, we maintain excellent financial flexibility to manage debt refinancing through the volatile debt capital markets we've been seeing lately, pursuing bolt-on transactions that can add scale to our core natural gas-based strategy like the Trace acquisition or to pursue stock repurchases. And I might just say a little more on the stock repurchases since I know it's an important topic out there. As you'll recall, we previously discussed initiating share repurchases based on reaching an undisclosed spread between our equity yield and our 10-year debt cost. Now obviously, since then, we've seen significant increases in our 10-year debt cost, which really would have made it increasingly unlikely that share repurchases would be triggered. So we did recently revisit those principles, and we're not only considering the current equity yield now, but we're also considering a level of expected growth in the business given the solid growth we've seen in the business now for many, many years. And the effect of this change will provide us more flexibility to be opportunistic around share repurchases, should we see a significant pullback from current valuation levels. And this might be the case if a recession gains strength and energy macro conditions were to deteriorate. And we have more confidence than ever in our ability to perform very well even through a severe recession, and we feel like our performance in 2020 during the heart of the pandemic really proved this to be true. So our current share buyback principles will allow us to act opportunistically if we see a valuation dislocation. And by the way, the strong free cash flows coming off our upstream JVs would be a great source of capital to affect share repurchases under these circumstances. So I hope that provides an overview on the capital allocation question. I think relative to the leverage, in particular, the 3.6 that we're guiding to now is obviously well below the 4.2 metric, which we believe is more of the ceiling for maintaining our strong BBB credit rating. We do continue to believe a BBB credit rating remains optimal for our business, and we are also mindful that our current metrics are benefiting from a pretty strong commodity price backdrop. But in any case, we are pleased with the financial flexibility we have had under the present circumstances and excited about our future prospects really no matter where the synergy cycle goes next.

Alan Armstrong :

Yes. I would say just -- I would just add to that, one contract with Chesapeake, we obviously have other customers out there, and we're picking up new business out there as a result of some of that returned activity. So we're excited to see that. But relative to the one contract that has the MVCs in it, it kind of -- there's ways to go, I would just say, to get over and above the MVC out there, and it would take pretty active responses from the producers. But we are excited to see the activity, and we are picking up business from other producers out there as well that's helping us out.

Jeremy Tonet:

Just want to come back to the Inflation Reduction Act a little bit, if I could. Just wanted to see, I guess, what are some of the things you're watching there that could positively influence your business specifically as it relates to the tax credits? If some of those do come to fruition, how that might that impact your view of CCS, hydrogen or other?

Chad Zamarin :

Sure. Yes. Thanks. I'd say we have announced potential projects in the CCUS arena. We're very active in exploring the hydrogen potential. We've been publicly discussing the fact that we're participating in four potential hydrogen hubs that were a part of the Infrastructure Act, the funding through DOE was part of the Infrastructure Act. So we've been actively pursuing multiple opportunities to prove out those areas. The proposed tax credit would be supportive of our strategy. Certainly the 45Q credits would be very supportive of our CCUS project in the Haynesville, which would be a project that will be built alongside our lake system that would decarbonize that project and production in Hayesville. So we're very excited to see that forward. And hydrogen still got a long ways to go. The projects that we think are being discussed are primarily in support of green hydrogen, and we've got great opportunities across our footprint to complement our infrastructure with green hydrogen production, but also seeing the CCUS credits and the hydrogen credits. Together, it would be the most impactful for supporting kind of natural gas production [to happen]. So we're encouraged with those. As we spoke on previous earnings calls, those projects are in line with our expectations, and we would see projects that will move forward based on those credits. And so I'd say stay tuned.

Micheal Dunn :

Thanks, Jeremy, this is Michael. Yes, Trace is performing as we expected. So, so far, so good. We've integrated the team there very well. And really taking hold of what the culture is here at Williams. So very pleased with what we're seeing there so far. On the rest of the Haynesville, we are seeing some great improvements year-over-year in regard to our gathering volumes there. So very pleased with that and across a great array of different producer customers -- we do have a number of expansions underway in the North part of the system. Some of that will come online later this fall, but we also have some in our South in Haynesville system that we are anticipating bringing on as well. So a lot of activity and associated expansion opportunities. We’re at a number of different producers there, both public and private and we've outlined that in the presentation materials, but these expansions are pretty reasonable costs as well from a capital investment standpoint just because of the backbone nature of the systems that we have built out there. We've talked about GeoSouthern driving a lot of new capacity through our systems that we had already built out a long time ago, and we're seeing the benefits of that now with these low capital investment opportunities that are driving very significant volume growth out of the Haynesville.

Brian Reynolds :

First question, I really want to just follow up on some of the capital allocation commentary previously. I appreciate the color. But as a follow-up, you talked about the spread between the equity yield and credit. I'm just kind of curious, just given Williams is heading towards a sub 3.5 leverage. Just wondering if there’s a point where Williams will consider sub-optimal leverage as another consideration in terms of the capital allocation framework in case Williams does not see that potential equity pullback alluded to?

Brian Reynolds :

Great. And then as a follow up -- appreciate the commentary on the tax credits. Maybe to talk a little bit more about the corporate minimum tax proposals. Any initial comments that you could have on the impacts to Williams? And then as it relates to NOLs, I know there's a difference between book hitting what you guys impact. So any initial takes on potential impacts to Williams there?

Operator:

Our next question comes from Gabriel Moreen from Mizuho.

Alan Armstrong :

Yes, Gabe, I'm looking at Micheal here to see if he had any insight on that. I don't know what would have dropped off of there, other than maybe we pulled the LNG, the LEG project off and moved that into execution. So that probably occurred is that the only thing because that was slated as an LNG project. So I expect that move. But other than that, I would tell you that we just continue to be impressed with the amount of demand for increased services on our Transco system, particularly in kind of the traditional parts of our market as well as a lot of opportunities for serving LNG in the Gulf. But I don't think there's been any shift in our business other than LEG project getting pulled from pipeline into execution.

Micheal Dunn :

Gabe, this is Micheal. Yes, I think we'll see some opportunity there to work that issue for the benefit of both ourselves and the third party there, one of them that had the issue. But right now, we are working to make sure we can accommodate volumes into our systems, but it looks like we'll be able to accomplish that and certainly helping industry out in that regard. But there will be some upside in Williams for the business that we'll take on there.

Michael Lapides :

Thank you for taking my question, as I have two of them. First one, you've gotten a lot of questions today on capital allocation. Just curious, you've made a lot of progress in moving forward with some new projects. Congrats on Regional Energy Access and EIS, by the way. Congrats on LEG as well. Just curious how you're thinking about growth CapEx for next year and the year after? And I know you're not going to give the actual number, but just directionally on -- you've got a lot of projects in the hopper. Should we think that growth CapEx in the coming years is a little bit above kind of where you're expecting this year to be?

Michael Lapides :

And then one follow up and this one is a little bit granular and I apologise. But just curious -- when you're thinking about your gas production assets in Wamsutter and in the Haynesville, just curious do you have like a hedging philosophy you want to stick to or the company and the Board in more general stick to? Meaning how much of like next year, do you want to have hedged going into the year relative to your production levels?

Micheal Dunn :

To add to that, in the Wamsutter, we want to be careful. We have a situation where we have a physical flow issue to three knobs. We will be pretty careful in Wyoming as well as to what we hedge up there going into the winter months.

Craig Shere :

First, John mentioned prospective, more accretive bolt-on opportunities in terms of potential uses of free cash flow. Can you opine on where you still see low-hanging fruit there, specifically with opportunities in the Northeast G&P as well as across the West?

Chad Zamarin :

Yes. I would just say that we remain very disciplined when it comes to bolt-on transactions. We are always looking for places where we can leverage our footprint, our scale. And we do see bolt-on transaction opportunities in the Northeast and continued consolidation in the Haynesville, and virtually across kind of our footprint, including some potential opportunities that complement our transmission and storage businesses. So we'll continue to evaluate those. But I would say, I think you'll see more of the same where we've been very disciplined in making sure that anything that we do has real synergies and leverages our strength. And so we continue to feel like there may be opportunities there.

Alan Armstrong :

Yes, Craig, I think you described that actually very well. We do have continued growth in the next year, but I would say that that's offset by kind of the current strip obviously in terms of pricing on the E&P space, but we do have growth in that as well. So yes, we're positioned for an attractive '23. But obviously, we don't have guidance out there, and that will be somewhat dependent on how prices actually realize next year on the E&P business. But certainly, a lot of volume growth to be coming on the E&P business through the balance of the year that will extend itself into '23. And the gathering volumes in the Northeast are going to be very durable. And the growth that we're seeing in the Haynesville will continue. So a lot of very positive tailwinds, I would say, right now for the balance of '22 as well as setting up for a very attractive '23. And then even as we get into '24 and '25, a lot of the transmission projects that we're executing on right now and the Deepwater Gulf of Mexico really pile on to what's a great base of growth. So we're pretty -- I would say we're pretty bullish right now about the way the next three years are stacking up in terms of very visible growth across the business right now.

Neal Dingmann :

Alan, you've touched a lot about this, but maybe a little more details on that, specifically your thoughts on maybe spending or specifically, could you talk about -- a bit of an update on your CapEx guide. I am just wondering -- you talked around that a little bit today comparatively in Q&A. I'm just wondering any more color you can give on that updated guide.

Neal Dingmann :

Yes, more for beyond, again, I kind of obviously get what you're doing this year and so more is expectations and kind of you've got a lot of exciting projects. So I'm just trying to get an idea of maybe sort of organic versus these other projects and as you said more in the sort of beyond?

Neal Dingmann:

Great. Great. And then lastly, just a quick follow-up. You've seen -- continue to see some great commodity price upside around those upstream JVs in years. I'm just wondering, can you help me a bit what -- I don't know if you can frame this a little bit, but what type of price sensitivity do you have? It appears to me that prices are going to stay higher, maybe even go higher. So I'm just trying to get a sense of sensitivity around some of those upstream JVs.

John Porter :

Yes, I think it's a little bit of a moving target. We have given some good volume information in the appendix of the presentation. Those volumes are ramping pretty quickly quarter-by-quarter right now, and we'll continue to do so into '23. So we'll continue to try to provide clarity around the volumes. We've also kind of laid out what hedges we put against those. So it's a bit of a moving target, and it will change each quarter as our net production volumes continue to increase and as the overall hedge portfolio changes. But we're going to continue to provide that information in the appendix every quarter so that you can keep up with how that's changing.

Alan Armstrong :

Okay. Well, thank you all very much. Thanks for the great questions. Another really terrific quarter and great setup for both the balance of the year and into '23. So we're really excited about where we're positioned today and really hopeful that some of the permitting issues are going to be dealt with in light of a lot of concern over the energy crisis that is beginning to be felt here even in the U.S. And so we think that's going to bring some attention to needed permitting reform, and we intend to be front and center in trying to make that good for both our country and from Williams as well. So we thank you for joining us today, and have a great day.

Danilo Juvane:

Thanks Sara, and good morning, everyone. Thank you for joining us and for your interest in the Williams Company. Yesterday afternoon, we released our earnings press release, and the presentation that our President and CEO, Alan Armstrong and our Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call today, Micheal Dunn, our Chief Operating Officer, Lane Wilson, our General Counsel, and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remark and you should review it. Also included in the presentation materials are non-GAAP measures that we reconciled to generally accepted accounting principles and these reconciliation scheduled appeared at the back the base presentation materials. So with that, I'll turn it over to Alan Armstrong.

John Porter:

Thanks Alan. So starting here on slide 1 with a summary of our year-over-year financial performance. Overall, ‘22 is off to a strong start. We've seen 7% growth in EBITDA or 13% if you adjust last year to remove the favorable effects of last year’s severe winter weather, including winter storm Uri. And as we'll see on the next slide, our core natural gas focus transmission and gathering and processing businesses have fueled this EBITDA growth. Although, we have also enjoyed continued strength in our Upstream and marketing businesses. Our adjusted EPS increased 17% continuing the strong trend of double digit growth we've seen now for many years. Available Funds from Operations, AFFO grew a bit more than EBITDA continuing the trend of strong growth in this measure, up 16% year-over-year. As a reminder, AFFO is cash from operations including JV cash flows, but excluding working capital fluctuations. If you compare AFFO to our capital investments of $316 million, and our dividends of $518 million, you see that we generated over $350 million in excess cash for the quarter. Also, you see our dividend coverage on this page based on AFFO continues to be very strong at 2.3x. Our debt to adjusted EBITDA metric continues to improve based on our strong growth and EBITDA and cash generation and our capital investment discipline. You see a nearly four tenths or 9% improvement in this measure in only a year. So now let's move to the next slide and dig a little deeper into our EBITDA results for the quarter. Again, another strong start this year with 7% growth reflecting the combined effect of the performance of our core business, and upside in our upstream operation. Walking now from last year's $1.415 billion to this year's $1.511 billion we start by isolating those favorable effects from last year’s severe winter weather which were $77 million, and are shown here in gray. Maybe just a quick opening comment regarding expense trends since inflation has been such a big topic lately, we've actually continued to see very solid cost control in our business. You may have noticed the $34 million increase in operating and maintenance expense on the face of our income statement. But this is really driven by a combination of higher reimbursable expenses that are offset in other fee revenue, new lease payments that were just the plan part of Transco’s Leidy South expansion project, and finally operating expenses associated with our new upstream operations. And related to the $31 million increase in SG&A on the face of the income statement, you should know that this is pretty much entirely related to the addition of the Sequent business. That also includes their bonus accrual and also an $8 million credit reserve related to a small customer bankruptcy. Moving next to our upstream operations on the waterfall chart here included in our other segment, upstream operations were at $56 million, excluding the $22 million of winter weather benefits from last year. Importantly, our first new Haynesville production only began in April so really no contribution in this $54 million yet from Haynesville. So the full amount of the growth is attributable to our Wamsutter properties. And it's a bit of an apples to oranges comparison at that. As a reminder, last year, we owned 100% of the acreage we acquired from BP only for February and March. But in the first quarter of this year, we owned 75% of the Wamsutter upstream JV which now includes the combined BP, Southland and Crowheart acreage. Shifting now to our core business performance. Our Transmission and Gulf of Mexico business improved $37 million, or 6%, primarily at Transco and largely from the Leidy South Expansion Project, which came online in phases last year. Overall, our average daily transmission volumes for Transco increased over 6% versus the prior year as we once again saw record winter natural gas demand. And Transco’s revenues are driven by reserve capacity, not actual throughput, but continued growth in actual throughput does highlight the criticality of Transco’s service. We also saw higher margins in our Gulf of Mexico business. Our Northeast G&P business increased $16 million, or 4%, driven by top line gathering and processing revenue growth on slightly lower volumes. G&P rate growth was supported by a combination of factors including higher commodity base rate, annual fee escalation and other expansion related fee increases that more than offset lower cost to service rate at our Bradford franchise. The slightly lower year-over-year Northeast volumes in the first quarter were anticipated in our initial guidance, and we expect a continued quarterly increase for the remainder of the year compared to the first quarter of ‘22 levels. We continue to expect a gradual increase in overall Northeast volumes throughout the remainder of the year. But ultimately, our plan for the Northeast in ‘22 continues to see higher EBITDA versus ‘21 on pretty flat volumes. However, we are well positioned to resume stronger volume and EBITDA growth in the Northeast in ’23 driven by several expansion and optimization projects underway that Alan will discuss in more detail. Shifting out to the West, which saw an impressive $35 million or 17% improvement over ‘21. In the West, we continue to see upside from our commodity price expose rates in the Barnett, Piceance and Haynesville as well as substantially higher volumes in the Haynesville that drove an 11% overall increase in volumes for the West. In the West, we see a strong quarter-over-quarter growth trajectory throughout the rest of the year, and especially in the second half of the year, driven primarily by strong drilling activity in the Haynesville. Next, you see a $30 million increase in our Gas and NGL marketing services business, which includes both our legacy gas and NGL marketing business as well as Sequent. This improvement was primarily caused by the addition of Sequent in July of last year. Overall, this segment produced $65 million of EBITDA. As a reminder, the first quarter of each year is typically when Sequent creates the majority of its EBITDA. And this was a strong performance for the team. While we expect to see $50 million to $70 million of annual adjusted EBITDA contribution for this combined segment, Sequent plus our legacy marketing business, this year we've gotten off to a stronger start than expected. And with the strong commodity price expectation for ‘22, we expect to exceed this $50 million to $70 million range. So again, another strong start to the year with 7% growth in EBITDA at over $1.5 billion, driven by core business performance and upside in our upstream and marketing operations. Let's move to slide 3 to look at our latest financial guidance thoughts for full year ‘22. We are pleased to share a substantial improvement in our ‘22 financial guidance versus what we provided in February of this year. I won't go through each of these metrics, but we'll offer some commentary on the most pivotal numbers. Let's start with adjusted EBITDA where our midpoint is increasing $250 million, moving from $5.8 billion to $6.05 billion with the [tightened] (ph) range of plus or minus $150 million versus the original plus or minus $200 million. This substantial raise in EBITDA guidance is grounded in our confidence and the continued growth in our core business before considering the Trace acquisition. Specifically, we expect steady quarterly EBITDA in our Transmission and Gulf of Mexico business through the remainder of the year. The continued quarterly EBITDA and volume growth from our West and Northeast segments, with some level of acceleration through the second half of the year. Additionally, for the remainder of ‘22, we expect a growing contribution from the Trace acquisition, which closed last week as it moves towards the targeted approximately 6x acquisition multiple based on its ‘23 EBITDA. And finally, with respect to our upstream operations, we are encouraged by the results we've seen thus far in ‘22 and remain confident in the fourth quarter exit rates we quoted at our Analyst Day. Shifting down the page now to growth CapEx you'll note a $1 billion increase in guidance from a combination of the $950 million Trace acquisition value and other Trace related CapEx. Note that we've closed the Trace acquisition using a combination of cash on hand and other sources of liquidity including our revolver and commercial paper. You see that our debt to adjusted EBITDA remained steady at 3.8x reflecting the balancing of our increase EBITDA with our increased growth capex portray. The remainders of the guidance items either changed in relation to the change in EBITDA that I just discussed or remain unchanged as in the case of maintenance CapEx. So again, a substantial increase in EBITDA dollars at the midpoint driven by continued growth in our core business as well as contributions from Trace acquisition and sustained expectations for our Upstream JV operations. So with that, I'll pass it back to Alan to review our key investor focus areas. Alan?

Danilo Juvane:

Operator, please open the Q&A line.

Brian Reynolds:

Hi, good morning, everyone. Maybe to talk on the EBITA guidance a little bit, I was curious if you could provide a little bit more colors, the upside and downside of the EBITDA range. First look at apples-to-apples comparison seems like commodity exposure is really the main driver of guidance in addition to the Trace acquisition. I am just wondering if you have anything to add to that, in addition to that, if there are any volumetric assumption changes to the guidance update. Thanks.

Brian Reynolds:

Great, appreciate that color. And then maybe as a follow up on just the evolving regulatory environment, it appears that there's some near-term tailwinds and support natural gas and LNG infrastructure permitting. I was curious if you could comment on this evolving environment and curious if Williams is considering adding new Transco growth projects for FERC approval for the docket that may not have been pursued in the last year, the beginning of this year? Thanks.

Operator:

Your next question comes from the line of Chase Mulvehill from Bank of America.

Chad Zamarin:

Sure, hey, this is Chad. So LEG is at full capacity to 1.8 Bcf a day project, we have over half of that contracted today, we would expect to achieve sufficient level of commercial contracts over the next couple of months to FID the project. We see a pretty significant need for volumes that are growing in Haynesville to get to Gulf Coast markets. And so I would feel pretty good about that getting done. Mike Dunn is going to talk about the capital project.

Chad Zamarin:

Yes, and important to just remember that when we executed on the Trace acquisition Quantum did, and we announced the Quantum will be an equity partner in the project. So that'll reduce our capital load a bit. And it could be that we bring in an additional equity partner in the project. So we will I think de-risk a portion of the capital budget and benefit of creating that full value chain from truly wellhead to water across our infrastructure and we'll work with our partners on the project to optimize the entire value chain.

Chad Zamarin:

Yes, I'll start and then Alan follow up. I'd say for the Haynesville strategy, the wellhead to water, there's a pretty good existing footprint of LNG export facilities that we're focused on connecting to. We are the largest infrastructure provider to the LNG terminals across the entire footprint. So for the near term, our focus is on making sure that our customers can access those LNG terminals. And also we can connect our customers to the very best markets, whether those are domestic or international. So I think our strategy of building that full value chain is not dependent upon us building and operating LNG terminals. And so our strategy today is to serve as a reliable supplier to LNG export terminal and then increasingly provide access to our customers to those LNG markets. I don’t know, Alan, if --

Operator:

Your next question comes from the line of Praneeth Satish from Wells Fargo.

Alan Armstrong:

Yes, that's a great question, I would say generally, probably not is because our returns on Transco have gotten to be very much higher than then the normal projects. And thanks to the efforts of the environmental opposition and making pipeline permitting so difficult in the areas that we operate, it's allowed us much higher returns in that space than would normally be allowed. So yes, it's definitely more competitive. We like it. Because we've got follow on business upstream and downstream with Transco. So it makes the kind of total incremental return on those projects attractive, but it is not as high as kind of bolt-on expansions that we see on Transco today just because of our strong competitive position in those areas.

Micheal Dunn:

Good morning, this is Michael, I’ll take the Northeast question. We saw in the first quarter of this year, really a convergence of several things that impacted volume in the Northeast, really across the entire basin. And a lot of that was driven by reduction increases that occurred in the fourth quarter of ‘21, where a lot of producers accelerated their well path connections early in order to hit great exit rates for the end of 2021, which was great for our systems. And we saw a lot of peaks on our systems in 2021. But that obviously hurt ‘22 performance in the first quarter with all of that really execution and then the decline that occurs from those new wells. So we saw that and we saw really significant winter weather in the Northeast this year, something that we haven't seen in several years of this magnitude and that did impact a lot of the production from the producer freeze off. And not only just on our systems and the producers on our systems, but the production that was gathered by others that would be brought to our processing facilities. We also saw some impacts there. So we did see inlet plant volume declined because of that. And then finally, we had a producer that had the well path that came online that had significant levels of condensate, which is good for them from a production standpoint, and it overwhelms their facilities. And so they weren't able to bring those volumes to us until they rectify that situation. And so that's been fixed. But that did impact some significant volumes from that producer in the quarter. So we had several big items that impacted that and developed and we expect an acceleration of volume coming on between now and the end of the year. And we have talked about volumes in the Northeast being somewhat flat this year, from some of the producers talking about being in maintenance mode, but we do see 2023 shaping up pretty well with the four expansions that we have underway across all of the dry and rich basin in the Northeast.

Operator:

Our next question comes from the line of Gabriel Moreen from Mizuho.

Alan Armstrong:

Yes, thanks for your question. I don't think we've released that sensitivity on price. We have said the contracts that we have, there are around our Laurel Mountain midstream business with EQT in the Marcellus has that feature as well as the Barnett gathering contracts in total and with total in the Barnett Shale, so those are kind of the two primary areas of exposure to those. There's a lot of areas of smaller ones, but in terms of any significance, those are bigger ones. But we have not provided that. In terms of the pricing that's in there, I would just tell you, it's, we're not counting on the kind of current pricing that we have, obviously for the balance of the year. And so we're being I would say a bit conservative about what we expect for the balance of the year, because we do think given the kind of growth that we're seeing in both the Haynesville and it's gearing up in the Marcellus and Utica that the workflows do, we can't very well on one hand, see the kind of prices to remain at these levels. And so I would say that those two things have to be considered jointly.

Alan Armstrong:

Yes, I would just say, we're as usual, we're going to be patient and picky and we've done that, and that served us well. In the case of Trace, we kind of caught that at from a timing standpoint. I think we caught that at a great timing, and we had unique considerations that we had to offer Quantum and Rockcliff they're both in terms of access to LNG markets via our LEG and Transco systems as well as an interest in LEG with Quantum which was valuable to them so we will continue to look for those kind of unique opportunities as they pop up where we've got significant value that we can add between us and environs, so I wouldn't say we're not going to look at everything because probably will, but I think we'll remain fairly patient and picky about how we choose our points of growth.

Jeremy Tonet:

Hi, good morning. Just wanted to touch on Appalachia a bit more and I guess the production outlook there and given how egress constraints impacts up production, just wondering now they have Mariner East online, you have the shell cracker coming here. With higher I guess egress or demand for NGLs? Are you starting to see any more pivot towards liquids rich areas? Or is it really focused still on dry gas more given the higher prices? Just wondering how your conversations with producers are going now when do you think -- how do you think that shape through could growth materialize this year or next year do you think, seems like it's --

Jeremy Tonet:

Got it. Thanks for that and just wanted to touch on higher net gas prices a little bit more, if I could. And whether these higher prices impacts you thoughts on monetizing William Center, Haynesville, ENP assets given the strong price in gas here. And at the same time, higher prices, more volatility leading to wider basis differentials. Do you see this kind of maybe driving more upside in through the Sequent operations in the near term given this backdrop?

Chad Zamarin:

Just that is the pace there. Currently, there are three -- at GeoSouthern is running in the Haynesville on our position and at that pace, we would see that reversion of interest on the undeveloped occur sometime in early 2023. So it's a kind of self-fulfilling in the Haynesville. So that'll happen naturally.

Michael Lapides:

Hey, guys, thank you for taking my question. One modeling one and one kind of citing and permitting longer term one, just on the modeling one, can you remind us I want to make sure I caught this correctly, what was the Sequent contribution in the first quarter? And what do you expect for the full year?

Michael Lapides:

Got it. And then on the permitting front, I know there's lots of discussion in DC about doing things that can make development of gas infrastructure asset easier over time, but we just saw the administration in the couple of weeks, revised the some of the NEPA related requirements for gas infrastructure, which strikes me that would actually make it a little more onerous in the citing and permitting process. And we just saw yesterday, a challenge to a license amendment for a Louisiana LNG project that already has an EIS. I'm just curious kind of from your thinking longer term, what do you think the messages that are coming out across the board or in terms of either from policymakers, environmental groups or others in terms of the desire but more importantly, the process for citing and permitting the asset infrastructure?

Michael Lapides:

Here just following the changes to the policy statement, making a draft and taking comments, et cetera, or something else along those lines?

Operator:

Your next question is from the line of Jean Salisbury from Bernstein.

Chad Zamarin:

Yes, this is Chad, Jean. Good question. I think that the Haynesville, it does have takeaway capacity that we see providing relief through probably the next couple of years. I would just note though, that the traditional angel capacity wasn't necessarily built to the markets that need the gas today. So it's not the most efficient path for getting gas to the growing markets, which is why our Louisiana Gateway project, we think makes a lot of sense, we are targeting that project moved directly from the Haynesville south to grow in LNG in industrial markets on the Gulf Coast. So we do see the capacity that will allow the Haynesville growth to continue over the next couple of years. But we see a need for projects to come online in the 2023-2024, sorry 1.4x timeframe.

Micheal Dunn:

Yes, Jean this is Michael, we are at capacity. We've got a lot of capacity available at the Rockies, for example. So I would say you'll see some uptick in activity out of the Rockies to move gas out of there with those pipes that were built historically to move that Rockies gas. So there's definitely opportunity to continue to increase from those basins that you called tier two. And we have a large footprint there, certainly in the Rockies. So we're pretty optimistic about that. We're seeing some drilling activity in the Barnett as well. But most of that is keeping production flat to slightly growing on our systems there, a lot of that's been drilled out and it’s more tough environment to drill in with mostly being urban there. But we are seeing some activity that's very pleasing to us with the rate structure that we have there in the Barnett. So I think for us, the producers with takeaway capability and available, you're going to see some increased activity if these prices continue as they happen.

Sunil Sibal:

Yes. Hi, good morning, folks. And thanks for all the clarity on the call. So I just wanted to go back to the venture capital fund, which was mentioned for clean energy and greenhouse gas monitoring. I was curious, if you could talk about the investment opportunity in there in terms of the size and threshold on returns on that?

Chad Zamarin:

Yes, if you look at that on the venture capital fund, we have been smart investing alongside proven venture capital investors that's not our core business, and is couple of existing funds. On the Context Labs investment we're actually investing alongside -- Energy Partners they are the largest investor in that platform which again we really like a highly credible investor who and are relatively small minority investment so does allow us to have significant impact over and how that technology will get develop in deployment and we want to make sure that we can help bring to market the very best de-carbonization solution and so I think the strategy of finding really promising technologies partnering with investment platforms that understand these markets and know how to put good money to work and then having RC at the table to influence the direction of the technology so that it achieves the goal that we are all trying to achieve and so that’s how we're approaching the investment strategy.

Micheal Dunn:

Yes, So, Sunil thank for the question. As we discussed in Analyst Day our upstream hedging program we've been pretty much focused on supporting our original street guidance and the underlying capital investments that we're making in those upstream businesses protect the plan, upstream gross margin, and those have been at favorable prices versus the original guidance. Couple points, though, because a good portion of our production volumes is really dependent on future production. We generally don't hedge more than about 70% of our expected exposure for the year. Also in this environment with the strong current pricing that we're seeing, we do expect that operators will push for volumes beyond what those original plans were, but until we see those volumes really materialized, we don't intend to hedge more than really 70% of those originally expected volumes. We do as we've already discussed, we do have significant contracts that direct exposure to prices as well above a floor, especially at the Barnett and in the Marcellus. So those contracts also provide us with exposure to gas prices beyond the Upstream JVs.

Alex Kania:

Great, thanks. Maybe just a follow up from earlier discussions on policy, but from the administration, you've talked about the agencies, but also do you think that there's a chance that we may be able to see some sort of kind of legislative kind of work being done that maybe kind of is kind of sort of an all of the above sort of strategy coupling clean energy incentives with kind of more focus on natural gas. And then maybe on a related question, on policy, are you seeing kind of this department of commerce review on solar kind of impacting your, I guess, the $100 million or so a placeholder that you've got for solar this year, or kind of whether it's impacting any thoughts for future years?

Chad Zamarin:

Yes, I would just say that we are watching proposed tariffs, we're watching the discussions regarding incentive structures for solar. And I will remind you that our solar program is primarily focused on installing solar and facilities where we utilize power that in many cases is more expensive than standalone solar that we can install. And so we are -- the economics of our investments are primarily driven by our ability to install solar projects that, frankly, compete even without incentives, and almost irrespective of some of the cost pressures that we're seeing. So as it relates to the $100 million that we've talked about this year, I'd say not so much affected by the policy issues. But I will say that we have, we're keeping a close eye on supply chain issues, we are under no time demand to install our solar facilities, by date certain and so we are going to make sure that we time those projects appropriately. We don't get caught subjected to higher prices than we need to pay for materials because of kind of supply constrained issues. And so we're keeping a close eye on the supply chain side of things, which has a much bigger impact, we think, at least for the projects that are currently underway, then kind of the policy issues that we're keeping an eye on.

Alan Armstrong:

Thank you very much, and appreciate everybody tuning in today and appreciate great questions. I just want to reiterate here on the backhand that the drivers for the growth for the balance of the year are really powerful and really across our base business, the Marcellus and Utica as we discussed, obviously, the Haynesville growth is powerful. And I think people are starting to see strong evidence of that. Deepwater business, we've got a couple of really nice tie in projects this year that will add to value towards the end of this year. And one set or later this year as our drilling operations pick up out there towards the very end of this year, we'll see volumes in the long side or that of course, will be driving the base business as well out there. And then finally, as I mentioned earlier, the Haynesville, we really haven't even seen the power of that yet on the E&P side. So first quarter was definitely not driven by that, because that's really a balance of the year and into ‘23. And really attractive earnings coming out of that area as well. So a lot of great quarter, but a whole lot of firepower left here to drive growth for balance of the year and into ‘23. And with that, I thank you for your attention today and look forward to talking to you soon.

Danilo Juvane :

Thanks [Indiscernible] Good morning, everyone. Thank you for joining us and for your interest in the Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our president and CEO, Allan Armstrong and our Chief Financial Officer, John Chandler will speak to this morning. Also joining us on the call are Micheal Dunn, our Chief Operating Officer, Lane Wilson, our General Counsel, and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and should review it. Also included in the presentation materials are non-GAAP measures that reconcile to generally accepted accounting principles, and these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

John Chandler:

Thanks, Alan. First of all, just what an incredible quarter we had, and a very high-level summary. The quarter benefited from nice increases in profitability from our Northeast Gathering systems and EPF lift in revenues on our Transco pipeline from new projects have been put into service over the last year. Significant contributions from our upstream operations in the Wamsutter and the benefit of higher commodity prices in our West segment. The positives were offset somewhat by slightly higher operating expenses resulting from increased incentive compensation expenses, reflective of the strong performances unfolding for the year. And you can see that strong performance in our statistics on this page. In fact, once again, we saw improvements in all of our key financial metrics. First, our adjusted EBITDA for the quarter was up $153 million or 12%, setting a new record. And we've seen a 10% increase in EBITDA year-to-date. We'll discuss EBITDA variances in more depth in a moment. Adjusted EPS for the quarter increased $0.07 a share or 26%. AFFO also grew significantly for the quarter, up $217 million or 25%. And AFFO, I'll remind you, is essentially cash from operations, including JV cash flows and excluding working capital fluctuations. If you put our year-to-date AFFO of $3 billion up against capital investments year-to-date of $1.2 billion and dividends year-to-date of $1.5 billion, you can see that we generated over $300 million of excess cash year-to-date. Included in those capital investments I just mentioned with $307 million of maintenance capital. Also, you can see our dividend coverage based on AFFO divided by dividends is a healthy 2.17x for the quarter. This strong cash generation and strong EBITDA for the quarter, along with continued capital discipline, has led to our exceeding our leverage metric goal, where we currently set at 4.04x net debt to EBITDA. You'll see later in our guidance update in the deck that we've moved our guidance for the year from where we were at less than 4.2x for the year now to around 4x at year-end. So really strong performance for the quarter and the year, and the fundamentals are set up for a good fourth quarter and a very good 2022. So now let's go to the next slide and dig in a little deeper into our EBITDA results for the quarter. Again, Williams performed very well, realizing a -- 153 million or 12% higher EBITDA. Our upstream operations added $55 million to adjusted EBITDA this quarter. This is almost entirely from the Wamsutter upstream acreage production from the combined assets, mostly from Wamsutter totaled 232 million CFEs a day for the quarter net to our ownership. Again, the Haynesville upstream acreage, but is very little EBITDA given it has only a small amount of existing PDP reserves. And therefore it will take a little time before we see new production and therefore EBITDA, coming from those assets. Our transmission Gulf of Mexico assets produced results that were 8 million more than the same period last year. New transmission pipeline projects added 24 million in revenue versus the third quarter of 2020, including the Southeastern trails project that went into service in the fourth quarter of last year. And a portion of aligning South project that also went into service in the fourth quarter of last year. And you can see this evidenced in the growth in our firmed reserve capacity, which is up 4% from the Third Quarter of last year. Offsetting this somewhat was Gulf of Mexico revenues that were down due to incremental impacts from hurricane shut-ins during the quarter from Hurricane Ida in comparison to the hurricane impacts from the Third Quarter of last year. Just so you have a number there, the incremental impact this year was a negative 5 million versus the Q3 of last year on hurricane impacts. In addition, the transportation revenue increases were offset somewhat by a slight increase in operating expenses, mostly due to employee related expenses. A large part of which can be attributed to higher incentive compensation accruals. The Northeast G&P segment continues to come on strong to attributing $46 million of additional EBITDA this quarter. Collectively, total Northeast gathering volumes grew 470 million a day for 5% this quarter versus the third quarter of 2020, while processing volumes grew 20%. The volume growth was predominantly at our joint ventures in the Bradford supply hub where we benefited from a gathering system expansion on that system in late 2019. And at our Marcellus South supply base and where we benefited from more productive wells at larger pads. And just to be clear, because we do not operate Blue Racer Midstream, those volumes are not included in the volume statistics I just quoted. As a result of these increased JV volumes, our EBITDA from equity method investments improved by $45 million, which also included the benefit of additional profits from blue -- blue ratio midstream, again, due to our additional ownership, we acquired in mid-November of last year. Otherwise, in the Northeast, higher revenues from higher processing volumes were offset by higher expenses. Again, with a significant portion of those expenses being related to higher incentive compensation accruals. You go to the West that segment improved by $48 million compared to prior year. 35 million of this increase is related to higher commodity margins due to higher natural gas and higher NGL prices. Otherwise, the remainder of the [Indiscernible] lift in EBITDA comes from lower operating cost due to lower maintenance fees and due to the absence of legal costs and small asset write-offs that occurred in the third quarter of last year. And revenues for the West were only up slightly compared to the same period last year. Now they're a number of big items that go opposite directions in revenues that I'd like to point out. First of all, for example, remember that we've lowered our gathering rates in the Haynesville this year in return for undeveloped upstream acreage from Chesapeake in the South Banfield area in Haynesville. The resulting gathering revenue decreased from this during this quarter was more than offset by rate increases in the Barnett and the [Indiscernible] where our gathering contracts allow us to participate in the upside when prices are higher. Also last year, our partner on Overland Pass Pipeline was paying us a deficiency fee to allow them to pull volume off of OPPL. Those deficiency fees do not exist this year. However, the assets of those fees are being offset by fees from prior gathering volumes otherwise. And to that point, overall gathering volumes in the West were up 1% with higher volumes in the Haynesville and the Piceance being offset somewhat by lower volumes in the Wamsutter in the Barnett. And then finally the Sequent segment produced near flat adjusted EBITDA for the quarter. Sequent traditionally makes a significant portion of its profit in the first couple of quarters of the year in the heart of the winter season. And therefore, did not realize profit for the quarter. Sequent does have significant portion of their transportation capacity hedged with basis swaps, as well as our storage inventory hedged with nymex positions, which of course led to the large $277 million unrealized mark-to-market loss on those hedges this quarter, as prices increased and as basis differentials widen in some markets. This, of course, means that the intrinsic value of our storage and transportation positions have gone up significantly as well. And again, you will see a significant portion of that value realized in the first half of 2022. Now to go to the year-to-date results. Again, our year-to-date results showed strong growth of $383 million or 10% and adjusted EBITDA. Many profitable things that are happening across all of our segments. First, I'd point to Winter Storm Uri, which added $55 million in profits to the West. And it contributed $22 million of income -- profit store upstream results. In addition, our upstream operations otherwise have added an additional $83 million year-to-date, almost entirely from the Wamsutter properties. Our transmission in Gulf of Mexico assets is up 30 million or 2% better, with the increase is being driven largely by additional transmission revenues from new projects that have been put into service and incremental revenues from Gulf of Mexico assets, largely due to lower downtime this year versus last year. These positives were partially offset by lower revenues due to a Transco rate place decline following the rate case final settlement in mid-2020 related to just a few markets. And as a reminder, a majority of our Transco rates actually increased in 2019. In addition, expenses are higher this year, year-to-date due to higher incentive compensation expenses resulting, again, from our strong performance. The Northeast [indiscernible] is up $124 million for the year, almost entirely driven by profits from our JV investments, again, mainly from the Bradford supply hub gathering systems and our Marcellus South gathering systems. In addition, we've benefited from increased ownership and Blue Racer Midstream. In total, gathering volumes for the Northeast are up 8% over the third quarter of last year, while processing volumes are up 22%. And then in the West, our West [indiscernible] is up $71 million, and this is on top of the $55 million that we earned from Winter Storm Uri. The $71 million increase is driven by higher commodity margins, higher gathering rates in the [indiscernible] offs where we participate in the commodity upside, and lower operating costs. These positives were offset somewhat by lower deferred revenue in the Barnett, Lower Haynesville gathering rates, which again, were exchanged for upstream acreage and lower Overland Pass Pipeline profits from lower actual volumes shipped and the elimination of the deficiency payments that we were receiving in 2020. And while we did see a 4% gathering volume decline year-to-date in the West, that was mostly offset set by minimum volume commitment payments. Again, this is stacking up to be an incredible year for us. In one of the thing I do want to point out we did pickup in some of the narratives from some of the analysts last night, the view that our operating costs increased and we did ourselves a bit of a disservice by not providing more information on our other operating segment where our E and P upstream operations reside. Actually, if you look on the face of our financial statements, our operating expenses went up $73 million. $12 million of that came from Sequent who, by the way covered most of that with their profits. E&P went up $51 million on costs, but of course, they're making significant EBITDA, so they're covering that with their revenues. And then the rest was related to bonus expenses. So our expenses actually doing -- when you extract Sequent and E&P and the bonus costs are actually down otherwise, so we actually are not seeing a significant -- or are seeing expense increases in pack with the contracts through other than the bonus-related expenses. So I thought I'd clear that up. I will now turn the call back over to Alan to cover a number of key investor focus areas. Alan.

Operator:

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Please stand-by while we compile the Q&A roster. Your first question comes from the line of Jeremy Tonet with J.P. Morgan. Your line is open.

Alan Armstrong:

Good morning, Jeremy.

John Chandler:

Yes. We did take an accrual for bonuses for the year, and both on our long-term incentive comp as well. I see a lot of [Indiscernible] adjusting that out of their EBITDA. We don't adjust that out of our EBITDA. So our long-term incentive comp did take some accruals for that as well as our annual bonus, which obviously with this [indiscernible] And so those -- that was a hit to the quarter that would be negative -- on the other side of that, we had about $24 million, I believe, of pricing increase on our NGLs and inventory, and so to the degree that that doesn't increase again, that would offset against that positive that shows up in the quarter. So that's a non-operational issue, if you will, we have to price that inventory up, but to the degree that NGL prices don't move again and that wouldn't show up. So that's just a couple of 1 positive, 1 negative. I will just say we pay attention to the forward strip when we think about our forecast and our guidance, and obviously, those are backward dated, as we sit here, and so our expectations would be the same moving forward as it relates to the E and P business. I will say that's not a huge driver of our business obviously it’s pretty [Indiscernible]. As you can see, it will become larger in '22 as we start to -- the Haynesville starts to get developed. That will be a net positive that where we will build larger sensitivity to gas prices in '22 as the Haynesville starts to, be developed. I would just say we know this was a good quarter in terms of pricing and we're not going to build our business in a way that's just sustained off of high commodity prices, and that's hopefully evident in how we forecast our business as well. Nice to take the winnings when they come to us, but we're not going to build -- we're not going to forecast our business around that. Obviously prices do stay high, then we'll certainly see the rewards.

Jeremy Tonet:

Moving along here, I guess next question I have is in the build back better build here. Just wondering what implications do you see for your business here it seems like it could be different things that 45 [Indiscernible] some other energy transition initiatives in a bill and at the same time, 15% minimum tax. Just wondering if you could walk us through some of the pluses and minuses that you see. The bill, if passed as written, how would it impact the [indiscernible]

Chad Zamarin:

Yeah, Jerry. This is Chad, just on the last note on the hydrogen front. The hydrogen incentives as currently drafted would be I think a good complement to our current strategy. And so we've been working closely on that front because that would be supportive as well as our -- supportive of our goals on that front.

Jeremy Tonet:

Understood. Thank you.

Christine Cho:

Thank you. Good morning. Maybe with the out-performance this year and [indiscernible] tracking below your target, how should we think about the execution of the buyback that you announced a couple of months ago?

Christine Cho:

And you would be okay with just having your leverage trend below 4x if the opportunity to buy back factored in presents itself.

Christine Cho:

That actually was my follow-up question around the modernization program. Can you just remind us how this works? How much you spend per year, the return how quickly you can earn on the spend and then I guess as you mentioned, what regulatory process we're looking at?

Christine Cho:

If you don't come to an agreement with your customers, would you have to recover it through a rate case or is there something quicker?

Christine Cho:

And the returns?

Christine Cho:

Great. Thank you.

Christine Cho:

Right. Thank you.

Shneur Gershuni:

Hi, good morning, guys. I wanted to start off a little bit here. You've had a strong performance last year, strong performance this year, or heading into the end of the year, you should be based on your guidance, you've had a growth target in the 5% to 7% range. The question I have is, does any of the performance in this year, takeaway from next year? But at the same time, you've announced several Mid Atlantic projects. You intimated that there's another one potentially coming in your prepared remarks. I was just wondering if you can share some detail about the return expectations of these new projects, and are they high enough to help drive growth forward. Is there a backlog of more of these projects that we can see more announced overtime?

Shneur Gershuni:

Really appreciate the color there. Maybe if we can return to the return of capital priorities. In your response to Christine's question, I think you were fairly clear in terms of you were looking for the opportunities to execute, but at the same time, your balance sheet is obviously doing better than expected. There's a priority over growth, how we discussed in the last question here. Just curious if one of the other arrows in the quiver shall we say, would be around the dividend. Are there any thoughts around a dividend step-up, or specials, or is there a different payout ratio that we should be thinking about as part of your return of capital strategies?

Alan Armstrong:

intent behind that was something special or some structure that delivered a bunch of cash then we would consider that. But right now, there's -- I think you should expect steady growth in our dividend that's well covered and very durable. And we think this is the business we've built, the long-term durable business as I think we've proven out. And we think that our yield on our dividend audit continued to trade down plus the durability and the growth in our dividend. And I think it's a pretty hard. Dividend to compete but frankly, given its security and the growth in it by both utility sector and within our peer group. And we think eventually we'll be rewarded for that.

Alan Armstrong:

Well again, I mean we've laid out the options. The market will tell us whether we need to buy back shares because it's presenting an opportunity or not. And if it presents itself. We'll be all over it. And if it does, the value will continue to generate through these other notes.

Operator:

Your next question comes from the line of Praneeth Satish with Wells Fargo. Your line is open.

John Chandler:

Yes. I don't know exactly where we stand up against peers. I know where we stand on the One Future measures, and we're almost orders of magnitude lower than what's required for our elements of the sector. So again, that One Future is a 1% all the way from the E&P space, all the way through the [indiscernible] or to the delivery to burner tips. so we're excited to be a part of that, but there's a certain percentage of that 1% that's allocated to our sectors of the business. And in those cases, we are way below and as I said, orders of magnitude below back. So we think we stand well, but we really don't know exactly where other competitors might stand on that. And therefore, what kind of advantage might [indiscernible] But I do believe that we need good, honest, reliable operators in this space that are going to be focused on methane emissions reductions. Ernest Moniz, back when he was Secretary of Energy, really made it clear to the gas industry that, hey, I love this industry, I think it has a lot to offer from an emissions reduction standpoint. But you guys have got to get your methane emissions. That's going to be your Achilles' heel if you don't go after this. And so we've been on a mission to reduce that. I think we're extremely well-positioned if the methane emissions are positioned right. And frankly, I think it's a real positive to make sure that we're reducing flaring, we're reducing emissions and VOC s from tanks in the field. I think all these things are very positive for our industry, and we certainly intend to continue to be a leader in that space.

Micheal Dunn:

Yes, it is in Chad, thanks for the question. Maybe starting with your last question. Yes, the incentives will be supportive in accelerating project opportunity. I mean, as we've discussed, hydrogen has been -- without an incentive structure and really needs an incentive structure to help support being projects jumpstarted. And I would also say that it's still early days on the hydrogen front. We're at the pilot stage. I would characterize project opportunities, but as far as our ambition goes, and if things prove out, if costs continue to come down, which we expect they would incentives get passed in Wyoming, for example, Alan talked about the potential to develop an energy hub in Wyoming in partnership with watershed and others. You could envision a very large

Micheal Dunn:

And I will tell you again, its very early innings, but the pieces are coming together and we're very hopeful, we're going to start by crawling before we walk and put some projects online that I think will demonstrate the feasibility, but that gives you just one example and they are looking at others across our footprint, but that's one example of where we think we can get to scale.

Operator:

Your next question comes from the line of Spiro Dounis with Credit Suisse. Your line is open.

Micheal Dunn:

Good morning. This is Micheal. We are watching with supply chain issues and the inflation issues very closely. We got in front of the supply chain concerns early on with treating chemicals and lube and things of that nature to make sure that we had what we need to operate the business. And I do would expect, we are seeing price increases, fuel, diesel, gasoline, prices are up through this small component of what our overall expenses are in business. And we could likely to be managed appropriately. As you mentioned, the bulk of our gathering and processing agreements do have escalators in them, so we are protected there on the gathering and processing side and on the transmission side, we could obviously take advantage of rate cases if we need to. But we've done a really good job managing our costs for several years now. And so we've been in very good shape for a number of years and managing that. And I suspect our teams will continue to do a great job at that. Going forward to year and take advantage of opportunities where we can to control our costs, but we will see some increased costs and there's no doubt about that. And the escalators that we have, there's various escalators that we use in the gathering and processing agreements. And I believe that would definitely cover the expense increases that we'll see.

Alan Armstrong:

Yeah. We've certainly positioned ourselves where well there to take part in projects that come up. And I would just tell you, so far, we like the risk mitigation that we get out of the kind of projects that we do with 2 or more market or unit and not 7 and 10-year kind of contracts that are just basis differential pipeline, that once that basis differential slides, they come out of the mining. And with a number of pipelines in the market today that fit that bill, every yard getting written down or struggling for re-subscription. Not yet in the Permian, but you say it's always an issue of risk-adjusted return and those are big risks on the back end of pipeline that are easy to use more on the front end, but hard to ignore on the back end. And we think about our business on a very long-term sustainable basis. And so tends to drive us towards longer-term contracts, and ones that we know that the value will be in there for the transportation for the long haul. I'm not telling you that we will be looking to take part, but with the returns would certainly have to be better than our other projects that we see within our capital stack.

Spiro Dounis:

Got it. Appreciate the color guys, and John, congrats on the upcoming retirement.