Good morning, ladies and gentlemen. Welcome to The Williams Third Quarter Earnings 2023 Conference Call. At this time, all participants are in a listen-only mode and please be advised that this call is being recorded. After the speakers’ prepared remarks, there will be a question-and-answer session. Now at this time, I’ll turn things over to Mr. Danilo Juvane, Vice President, Investor Relations. Please go ahead, sir.

Thanks, Bo, 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 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.

All right. Well, thanks, Danilo, and thank you all for joining us today. As our first slide here shows, Williams delivered another quarter of impressive accomplishments, starting out with our operational execution. So first of all, our project execution team completed the first half of Transco’s Regional Energy Access project well ahead of schedule, and our commercial and government affairs teams followed up with the contracting and FERC authorization needed to place this in service and begin full-rate revenues for the initial capacity here in late October. So great efforts by our teams there and great results in a very difficult area. We expect the total project to be online in the fourth quarter of next year, with the capacity to move approximately 830 million cubic feet a day of natural gas from the Northeast part of the Marcellus into the Pennsylvania, New Jersey, and Maryland markets. We also completed several other expansion projects, including a fully contracted gas transmission line that enables our newly acquired NorTex storage system to directly serve new gas-fired generation markets in that area. And in our West Gathering segment, we completed a large expansion of our South Mansfield gathering system in the Haynesville for GeoSouthern, which, I am proud to say, was the nation’s fastest-growing gas producer last year. In the Northeast, we completed the first expansion of many to come on our Cardinal gathering system for Encino’s rich gas drilling operations in the Utica condensate window. But the really big news this quarter comes in the new projects column. We recently signed precedent agreements of over 1.4 Bcf a day for the Southeast Supply Enhancement project, which provides takeaway capacity from Station 160 – from our Transco Station 165 to the fast-growing Mid-Atlantic and Southeast markets. Based on the open season results, we have even more demand to be met in the future that would likely result in a follow-on project. So we are proceeding into the permitting process for this initial project due to the urgent demands to be met for this first group of customers. In terms of impact, this will be the largest addition of EBITDA ever for a Williams pipeline extension, yes, even more than our Atlantic Sunrise project and, in fact, significantly more than the entire EBITDA generated from our Northwest Pipeline system. I’ll remind you that these are 20-year contracts from the time the project starts up, which would be at least through 2047. We recently signed anchor shipper precedent agreements for a Uinta Basin expansion on our MountainWest system. We continue to be very pleased with the successful integration of the MountainWest assets into our operations and the opportunities we see to execute on more profitable growth with this asset than we had originally planned on. This is the second piece of substantial business that we have signed up just this year on the MountainWest Pipelines, and neither of these expansions were in our pro forma for this acquisition. We are pleased with the team from MountainWest Pipeline and the leadership we have working to grow that business, but we are very pleasantly surprised with that acquisition today. Moving across the slide, we are acting on opportunities that we believe will further high-grade our portfolio of assets. First of all, Williams recently sold its Bayou Ethane Pipeline system for $348 million in cash. This represented a last 12-month multiple of over 14 times our adjusted EBITDA. The proceeds from this asset sale, along with expected proceeds from a recent legal judgment, will help fund an important strengthening of our hand in the DJ Basin with two transactions. First, the acquisition of Cureton Front Range LLC, whose assets include gas gathering pipelines and two processing plants to serve producers across 225,000 dedicated acres that are just to the north of our existing KKR system. Second, we purchased KKR's 50% ownership interest in the Rocky Mountain Midstream, resulting in us now owning 100% of that. KKR was our partner in Rocky Mountain Midstream. They’ve been a great partner there, but it was time to exercise that partnership agreement. We are pleased to have had the relationship with KKR, but this is an exciting expansion of our business which will allow us to deliver volume into our downstream assets, including taking existing gas supplies and feeding them into our Rocky Mountain Midstream. These acquisitions have a combined value of $1.27 billion, and this represents a blended multiple of approximately seven times the 2024 adjusted EBITDA. The synergies here are very tangible to us because we can just take these existing gas volumes, feeding them to our processing, and then enjoy the downstream NGL transportation, fractionation, and storage. The transactions are expected to close by the end of 2023, making Williams the third largest gatherer in the DJ Basin and progressing us toward the company’s strategy of maintaining top positions in the basins we serve. Additionally, we are taking over the operatorship of the Blue Racer gathering and processing system in West Virginia and Ohio later this year. This is important due to our ability to significantly lower costs and more easily capture synergies between this and our other operations in the area. We are continuing to advance our efforts to commercialize clean hydrogen through our support of two clean hydrogen hubs that were announced by the Department of Energy last month, one in the Pacific Northwest and another in the Appalachian region. We are looking forward to leveraging our operating expertise and our right of ways into the emerging hydrogen space. Looking at some of our financial highlights from the quarter, John will obviously get into more details here in a minute, but overall, we’ve delivered another quarter of strong financial performance even in the face of dramatically lower gas prices compared to the third quarter of 2022. Year-to-date, our adjusted EBITDA is up 9%, our adjusted EPS is up 11%, and gathering volumes are up 6% versus the first nine months of 2022. We expect the strong performance to continue, providing us with the confidence to raise our 2023 guidance this quarter up by $100 million to $6.7 billion of adjusted EBITDA. We are tracking in line with our 5% to 7% adjusted EBITDA annual growth rate, and this quarter marks the 34th quarter of meeting or beating the adjusted EBITDA consensus and the fifth time we have raised guidance during the same period. I’ll also point out that we haven’t achieved this by lowering our guidance. In fact, we have not lowered our guidance during this entire period, and that includes through the pandemic. In summary, our strict adherence to our strategy, our commitment to an improving return on capital employed, and extraordinary execution by our team have continued to deliver predictable growth through a variety of commodity cycles. Importantly, this discipline also has Williams positioned to capture significant future growth and return this value to our shareholders. With that, I’m going to turn things over to John to walk us through the financial metrics of the quarter.

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 increased by 6% over the prior year’s third quarter. Last year’s third quarter saw very favorable commodity prices for our marketing and upstream joint ventures, which made for a tougher year-over-year comparison in total, but we still grew 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 by 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. For the 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 were generally flat with last year's strong cash flow, and we see our third-quarter dividend coverage based on AFFO was a very strong 2.26 times with a dividend that grew by 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. 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. Let's turn to the next slide and take a 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. 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, those rates significantly lifted from the floor values they had been at for many years, and in 2023, we've seen them return back to their floor values. Our core business performance, particularly in our Transmission & Gulf of Mexico business, improved by $83 million, or 12%, including about a $47 million contribution from our MountainWest Pipelines and NorTex acquisitions. We also saw 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. As we've discussed 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 the 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. Shifting now to the West, which decreased by $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. The gas and NGL marketing business experienced a $22 million decrease. 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, including a $36 million decrease driven by 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. The third quarter continued our strong base business performance in 2023 with 6% growth in EBITDA driven by core infrastructure business performance despite natural gas prices that were 68% lower than the third quarter of 2022. 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. Walking now from last year's $4.6 billion to this year's $5.1 billion, looking at our core business performance, the Transmission & Gulf of Mexico business improved by $210 million or 10%, primarily due to the impacts of the MountainWest Pipelines and NorTex acquisitions. The Northeast G&P business has performed very well with a $138 million or 10% increase driven by a $217 million increase in service revenues. This revenue increase was fueled by a 6% increase in total volumes focused in our liquids-rich areas, where we have higher per-unit margins than our dry gas areas. 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. The strong base business performance in 2023 has led to 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 a $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 led to some recent shut-ins, and after that historically difficult winter that continued to have unfavorable impacts through April of this year. This 2023 guidance raise comes after two consecutive years of record-breaking adjusted EBITDA growth in 2021 and 2022. The appendix contains other positive shifts in our financial guidance metrics that are generally aligned with the higher EBITDA guidance. Regarding our 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, which is still growing each day for interest charges as well. Considering all 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, DJ transactions, and about $130 million of share buybacks that we've done this year. In summary, we are finishing 2023 with a guidance raise that builds on a strong multiyear trend of outperformance, setting our sights on continued growth in 2024 before another significant growth step up in 2025. With that, I'll turn it back to Alan.

Okay. Well, thanks, John. Just a few closing remarks before we turn it over to questions. First, I'll start by reiterating our belief that Williams remains a compelling investment opportunity. We are the most natural gas-centric, large-scale midstream company around today, and the tightly integrated nature of our business is unique. Second, our combination of proven resilience, a five-year EPS CAGR of 23%, steadily growing two times covered dividend, a strong balance sheet, and high visibility to growth is unique among the S&P 500 and within our sector. Our natural gas-focused strategy has allowed us to produce a ten-year track record of growing adjusted EBITDA through a large number of commodity and economic cycles, and it is continuing to deliver significant growth in the current environment. The signals coming from the market show that it will continue to deliver substantial growth well into the future. Shoring up our nation's and the world's energy foundation with natural gas will happen whether the opposition wants it to or not, because we are running out of time and real-world options to meet the growing need for energy while reducing emissions. Natural gas is the most effective non-subsidized way of reducing emissions and has become the practical alternative. Ramping up the production of natural gas has enabled the U.S. to meet our evolving domestic needs as well as provide energy security and support to our global allies. It stands unmatched as the most affordable and reliable source of energy and has been the most effective tool to date at reducing emissions. At Williams, we are committed to a clean energy future that focuses on driving down emissions while protecting affordability and reliability. The drive for electrification is on, and dispatchable power capable of keeping up with the growing number of government incentive electrical loads like carbon capture, hydrogen production, and data centers will largely be served by natural gas. This includes scaling up renewable sources to reduce carbon, while backing up those sources with the flexibility, scale, and reliability of natural gas. We are here for the long haul and committed to leveraging our large-scale natural gas infrastructure network for the benefit of generations and our shareholders for generations to come. With that, I'll open it up for your questions.

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

Thanks, operator. Good morning, team. Maybe to start with Southeast Supply Enhancement. Alan, you mentioned that being the largest EBITDA contribution I think you said we've ever seen, which, at least for us was maybe something we didn't appreciate. So curious if you could provide a sense of how you think about the capital costs, maybe even the returns around the two phases of that project. Also, if you could just talk about some of the physical capacity at 165 today to handle volumes when MVP comes online. I know it's something you've addressed in the past, but it still seems like some level of confusion there.

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 gotten 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 are based 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. The EBITDA that I mentioned 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. We are excited that capacity is precious, coming out of there. To remind you, 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. That's the existing capacity that we have from 165 today. Obviously, there's a lot of demand for that capacity, so it's not like it's just available for somebody to come in and buy. That’s why we're able to put together such an attractive project here, utilizing our existing right of way and structuring it in a way that will provide the least points of resistance from a permitting standpoint for an expansion south. So it's really not a terribly complicated project; easy for me to say that, as I'm not responsible for getting it done directly, but it is on our existing right of way and avoids a lot of the typical wetland issues that we encounter and tend to snag the permitting process. Great job by the team in working with our big customers out there in meeting their very urgent needs and providing a very attractive project. Couldn't be prouder of the team.

Got it. Helpful color, and I appreciate the clarification on the EBIT contribution for that first phase. Second question, maybe just turning to these two DJ Basin acquisitions. It sounds like downstream benefits also drove part of the decision to expand there. So two questions on that front. One, does that 7x blended multiple include any downstream benefits, or is that sort of standalone for the assets? And then two, how should we think about the Cureton NGL volumes coming onto the downstream system? Is that something that happens immediately, or do we need to wait for contracts to roll off?

Yes. Thanks, Spiro. The 7x multiple really reflects the standalone acquisition value, and we do see significant opportunities to integrate those assets. It will take a little bit of time, as there are some current commitments, but Cureton has more volume that they're gathering than they can process and deliver into downstream infrastructure. Rocky Mountain Midstream has some excess capacity. So we're going to be able to consolidate those volumes and move a substantial amount of incremental NGLs down our infrastructure. However, some dedications over the next 12 months and beyond will roll off, allowing us to move those volumes fully over to our system, so you'll see that value increase over time.

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

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

Hi, good morning. Thanks for taking my question. First on a macro level, it seems like some of the Southern Utilities are worried about having gas supply, especially with a lot of the Haynesville moving north to south with projects like your LEG pipeline. Are you seeing interest from Southeast customers rather than Southern Utilities to move Haynesville gas on Transco towards that area?

Yes, it's a great question, actually. I think the market will figure that out. For instance, our LEG project is structured such that it will give people the opportunity as they come in at that location, allowing 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. 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. I believe that producers may not have to declare one way or the other as much as they'll be positioned to enjoy the benefits of either one of those markets. We're certainly going to see competition for Haynesville supplies that have traditionally come into Station 85, and that will certainly be in competition with 165 for a while. That will dictate which way the volumes flow on there. The big LNG capacity growth is not 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 will take away supplies that many Transco customers have depended upon coming into Station 85. To your point, that’s why we’re seeing such an interest in picking up supplies off of the Mountain Valley Pipeline. But I also believe that largely, the market's growing in those areas is what's driving that as they start running out of options for meeting power generation loads in those areas.

It’s important to note that this is not a near-term macro. This macro setup will evolve over the next decade and beyond as LNG demand increases and power demand on the eastern side of the United States continues to change. There will continue to be competition between utilities and LNG exporters for natural gas, and there is no better asset setup to benefit from that and provide the supplies that are needed than our footprint in the Transco system.

Great. And then my follow-up, your Texas to Louisiana Energy Pathway Project, I think it’s roughly $364 million a day in 2025. It seems that 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?

Hey, Neel, it’s Michael. Thanks for the question. The TLEP project is just awaiting the 7C permit. We expect that to be imminent, so we’re excited to get that one off the ground. That’s really the first opportunity we’ve had to significantly increase our capacity from the South Texas area into the LNG corridor on the other side of Houston. We have many great opportunities to continue expanding that pathway on Transco. We have considerable looping capabilities in that area, additional compression that we can add, and we can really move a significant amount of gas from South Texas or the Katy area over to the Texas-Louisiana coastline where the LNG facilities are being contemplated for expansion. We are in discussions with parties on both sides, whether they be producers or consumers of the gas on both sides of that opportunity. The biggest impediment is Houston; as you probably know, that’s where the Transco pipeline system reverses just north in that corridor. We have one of the best quarters, in our opinion, to expand from the west side of Houston to the eastern LNG corridor.

Got it. Just to follow up on that answer, what’s the FERC lag in terms of approving a loop? I know compression is much easier; 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 complete the compression?

Right now, FERC has lowered their hurdle for smaller projects like TLEP. It was originally an environmental assessment, and FERC came back and said, 'No, we need an EIS,' but then pivoted back and said, 'No, this can go under an environmental assessment,' which is a quicker process. You save about six months to nine months on the environmental review typically between an EIS and an EA. Any looping project of any magnitude will most likely require an environmental impact statement, whether it be a looping or a greenfield project. The environmental impact assessment process typically takes one and a half to two years from filing to 7C approval. Looping projects are less controversial when you talk to environmental organizations and landowners. We’ve obviously been in the area for a long time; we have built relationships, and landowners are much more receptive to a looping project than to a greenfield pipeline. The environmental impact is less as well. So I believe you have a better opportunity for approvals for looping projects because they are typically less controversial, and FERC is interested in condemnation authority in using that, giving us a great benefit when we're looking at looping projects.

Great. Thank you very much.

Thank you. We’ll go next now to Theresa Chen at Barclays.

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 multiple with the downstream synergies? Are there additional opportunities for portfolio optimization going forward?

Yes. Thanks, Theresa. This is Chad. I won’t speak specifically, but we are typically looking for leveraging our footprint and our strategic positioning where we operate. We’ve focused on bolt-on transactions that provide better than one or two turns of synergies and optimization. This integration allows us to both increase gathering and processing. Additionally, we can move the NGLs down Overland Pass with our partnership with Targa, which allows us to move the barrels all the way to Mont Belvieu, where we have interest in fractionation. There’s a lot of opportunity to capture synergies along that value chain. Those are the types of opportunities that we are looking for, which provide clear commercial and operational synergies. We’ve made great progress cleaning up inefficiencies within our business. This is also the last of the non-operated joint ventures that we participate in. We will continue seeking opportunities to do that, and with the scale and geographic footprint we have, these low-risk, high-value bolt-ons will continue to be opportunities.

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

It’s too early to really speculate as winter is just getting started. The great thing about the Sequent platform is it’s set up to be a very low-risk platform. We can sit and be opportunistic as weather events materialize. But at this point, we’re cautious about over-interpreting or trying to over-predict the weather itself. We are well positioned for winter if we see dislocations, but that asset footprint is primarily structured for basis differentials and differentials in time, so we will continue to monitor the weather. Overall, we feel good about how we’re set up.

We’ll go next now to Jean Ann Saulsbury at Bernstein.

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 would be pushed back if MVP starts a lot later than expected.

No. Just to be clear, the agreements start when we place the expansion in service. The clock starts on those agreements for 20 years, so the reference to 2047 is based on that. It’s pretty optimistic to think we would have that in service in 2027; it would likely be the latter part of that from a timing standpoint, but we’ve set it up for permitting success. The timing on those terms doesn’t depend on Mountain Valley Pipeline. Many of those agreements are dependent on MVP coming into service, but not under that timeline.

Got it. I think I meant more for you to have the project online. If Mountain Valley gets pushed back, would your start date also have to get pushed back?

Yes. If MVP doesn’t get done, it’s still very low probability that we wouldn't be placed in service, but that would mean those markets would have to receive supplies from somewhere else. So we would need to come up with another way of getting those supplies to them.

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

Right now, our plans would be for it to all come on at once.

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

Sure. Chad, do you want to take that?

Yes. Fundamental base business benefits. Pipeline infrastructure is built to mitigate basis. We like the setup, certainly near term, from a marketing, storage, and optimization perspective. Volatility and basis differentials drive value across our core infrastructure. That’s why we think we are well set up to continue growing our base business and layer in as kind of the cherry on top, layer in these other assets and capabilities that capture that volatility. At the end of the day, our business is converting volatility in infrastructure, and that’s what we’re focused on. We believe we’re well set up to follow basis differentials and volatility and bring infrastructure solutions to help mitigate that long term.

Makes a lot of sense. Thank you.

Thanks.

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

Hi, good morning, everyone. To peak ahead to 2024, excluding today’s acquisitions, we have some tailwinds around full year Mountain West and some small expansions with hedging headwinds. It seems like, but I’m curious if you can talk about the existing base business and whether there are any rising tides regarding volumes or 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.

The base business is continuing to grow nicely. The growth we see in the gathering business next year will depend somewhat on producers' responses, which depend on the prompt price and the shape of the forward curve. On the transmission business, our opportunities are the acceleration of existing projects. The team has done a great job like they did on REA in bringing that first phase in early. If you consider our projects, most come together, including the deep-water business towards the end of 2024. Accelerating those projects would present opportunities for tangible growth, which will drive a large increase in 2025. It’s a little too early right now to call what we’ll see from the producer community in 2024, and that will likely drive that on the margins. I’ll let John provide some specifics.

I don’t have much to add. I think a good reference for considering our growth in 2024 and beyond is in Slide 18 in the appendix. You’ll spot several projects contributing to 2024 based on what we know, including several projects in transmission, the deep-water Gulf of Mexico business, and the gathering and processing expansions. You mentioned the full year of the MountainWest Pipeline acquisition and the DJ transactions we are discussing today will layer into 2024. Additionally, we will work against the absence of gathering and processing-related hedges that we had in place in 2023. The appendix clearly demonstrates projects that will drive growth in 2024 and even larger growth in 2025 and beyond. It identifies various projects that could contribute upside if we can bring them in early.

Great. Thanks. Makes sense. Maybe as my follow-up, we’ve seen the market talk about NGL and LNG opportunity sets over the next three to five years, with some downstream expansion opportunities. I’m curious, given Williams' strategic position on the transmission business, if you could refresh us on your $1 billion to $2 billion CapEx run rate and whether we could see some lumpy attractive projects ultimately move into the backlog, allowing us to grow returns given the anticipation of 20 Bcf of natural gas demand over the next decade. Thanks.

We are careful to not add projects to the backlog until we have a high level of optimism about them moving forward. I would be surprised if we don’t see many of those projects in our pipeline progress given the high demand and the many projects in our pipeline. We have the infrastructure to serve this demand. I would find it very unlikely that we would not see additional projects come in to help serve these gas demand increases. If you look at the alternatives for power generation, in the Northeast, for example, offshore wind is looking unlikely within the decade. People are going to have to get sober quickly about those alternatives. Our customers on REA made a smart decision for taking that capacity, as it will be in precious demand. Harsh realities in the Northeast will impact others regionally, while we’ve seen a strong demand in the Mid-Atlantic beyond the initial project we’re building there and into the Southeast is definitely growing. The LNG market continues demanding more infrastructure in areas where we’re well positioned to serve. There will be a lot of that backlog will transition into significant projects in 2025 and 2026.

Great. Super helpful. Hopefully, we will see more returns like Southeast Supply. I’ll leave it there. Enjoy the rest of your morning.

Thank you.

Thank you. We go next now to Jeremy Tonet at JPMorgan. Excuse me.

Hi, can you hear me now?

Yes. Got you, Jeremy.

Thank you. Good morning. I wanted to start off regarding capital allocation. As you’ve discussed at different points during the call, particularly with regard to higher rates, how does this impact the return of capital hurdles for capital deployment, specifically thinking about the dividend rate now that price appreciation has increased the yield a bit? How does all of this mix together with higher rates today?

I don't think we really have any significant changes to the returns-based approach we’ve been using for capital allocation over the last couple of years. We have seen a slight uptick in our borrowing costs, but we're managing through that pretty well. You’re seeing strong returns on many of our projects, as we’ve discussed, with the Southeast Supply enhancement being stronger than ever. The spread in our business between invested capital returns and our cost of capital remains strong and continues improving over time. Our capital allocation decision matrix remains unique, as we can make significant investments into our regulated rate base and achieve regulated returns. We have a rate case coming up next year, and we'll revisit the ROE on our Transco rate base. I think you’ll see us continue to monitor the returns on share buybacks against the potential for additional investments, and if we see dislocations in stock price based on current yield and growth outlook, we’ll quickly act to buy shares as we’ve done in the past.

On a macro level, surprisingly, higher interest rates are good for this business overall. Given the structure of our gathering contracts, inflation adjustments apply to the overall rate, not just to the operating cost, which pushes our operating margin up. We don't plan on inflation rates continuing long term, but to the degree that it does, it's a net positive for us. Plus, the impact of high-interest rates puts pressure on people's need to consider natural gas as a real-world alternative for power generation demand. Put simply, a gas-fired generation facility has a significant advantage on capital costs associated with it, but a disadvantage on fuel cost. The fixed capital element of power generation is very favorable for natural gas due to significantly lower front-end capital requirements. We're in a very favorable environment right now for our business and industry in general, as the higher interest rates increase the necessity for natural gas to meet growing power generation demands in the markets we serve.

Got it. Makes sense. I’ll leave it there. Thank you.

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

Thanks. I guess I’ll start with a high-level question, which may touch on your prior remarks, Alan. As you mentioned, there’s pressure on offshore wind and even solar deployments under the higher rate environment. As you talk to your utility customers, have you observed any shift there in their long-term perspectives on natural gas? Any adjustments in their decarbonization timelines?

For a number of reasons, we're seeing shifts in the Southeast and Mid-Atlantic. They’re experiencing rapidly growing demand from things like data centers and industrial load. However, the Northeast yet to respond; they’ve been holding onto their plans for offshore wind, which may change as harsh realities hit them. We see ourselves as a complementary player to renewables and are supportive of their developments. But in the Northeast, a significant shift is not yet apparent. We are seeing a shift mainly in the Mid-Atlantic and Southeast markets as they contend with demand growth.

It's important to remember that the fundamentals of the eastern third of the U.S. currently have less than 10% intermittent resources today. They are just getting started deploying alternatives like solar and wind. By 2040, peak gas demand is expected to double. Utilities recognize they will need gas here and now to achieve decarbonization goals.

Got it. 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? If so, would you expect some of the NGLs picked up from the DJ assets to potentially backfill any volume loss on OPPL?

Yes, I suspect that if and when ONEOK gets the Elk Creek expansion completed, we will see decreased Bakken flows on OPPL, as they have been diverting some of those flows into that asset. We have the space on OPPL today to accept DJ volumes, so it’s really not a constraint right now. However, having more capacity is always advantageous on OPPL as more DJ volumes come in.

Got it. Thank you.

Thank you. Ladies and gentlemen, that is all the time we have for questions this morning. Mr. Armstrong, I’d like to turn things back to you for any closing comments, sir.

Thank you. Thank you all for joining us today. It's exciting to announce many accomplishments in the quarter. I think we have a clear picture of the kind of growth ahead. I am very excited for the current performance and even more excited about the growth and signs of further growth that we’re seeing across our strategy right now. Thank you for joining us, and I look forward to speaking with you next time.

Thank you, Mr. Armstrong. Ladies and gentlemen, that does conclude the Williams Third Quarter Earnings 2023 Conference Call. Again, I’d like to thank you all for joining us and wish you all a great day. Goodbye.