The Williams Companies, Inc. (NYSE:WMB) Q3 2023 Earnings Call Transcript

The Williams Companies, Inc. (NYSE:WMB) Q3 2023 Earnings Call Transcript November 2, 2023

Operator: 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.

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.

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 and 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 beginning 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 proud to say was the nation’s fastest growing gas producer last year. And 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.

And based on the open season results, we have even more demand to be met in the future that would result likely 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. So 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. And I’ll remind you that these are 20-year contracts from the time the project starts up, which would be at least through 2047. And we recently signed anchor shipper precedent agreements for a Uinta Basin expansion on our MountainWest system.

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Q&A Session

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. In fact, this is the second piece of substantial business that we have signed up just this year on the MountainWest Pipelines, and neither of which of these expansions, neither of these were in our pro forma for this acquisition. So really pleased with the team from MountainWest Pipeline and the leadership we have working to grow that business, but 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 our Bayou Ethane Pipeline system for $348 million in cash. And this represented a last 12-month multiple of over 14 times our adjusted EBITDA. The proceeds from this asset sell along with expected proceeds from a recent legal judgment will help fund an important strengthening of our hand in the DJ Basin with the following 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. And second, the purchase of KKR is 50% ownership interest in the Rocky Mountain Midstream, which results in us now owning 100% of that. So KKR was our partner in Rocky Mountain Midstream.

They’ve been a great partner there, but it was coming time via those agreements to exercise that. So we’re really pleased to have had the relationship we had with KKR and a great partner there. But this is really an exciting expansion of our business out there that will allow us to deliver volume into our downstream assets and including taking existing gas supplies and feeding them into our Rocky Mountain Midstream, so really excited about that. These acquisitions have a combined value of $1.27 billion, and this represents a blended multiple of approximately 7 times the 2024 adjusted EBITDA. So the synergies here are very tangible to us. Again, because we can just take these existing gas volumes, feeding them to our processing, and then enjoy the downstream NGL – the coupon clipping on the downstream NGL transportation, fractionation and storage.

These are – the transactions are expected to close by the end of 2023, making Williams the third largest gather in the DJ Basin and progressing us towards the company’s strategy of maintaining top positions in the basins we serve. So, just a few other items to hit on this quarter. We finally are taking over 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 cost and more easily capture synergies between this and our other operations in the area. And lastly, we’re 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 one in the Appalachian region.

We’re 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 as 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. And 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. And we are tracking in line with our 5% to 7% adjusted EBITDA annual growth rate and this quarter marks the 34th first quarter of meeting or beating the adjusted EBITDA consensus and the fifth time we have raised guidance during the same period and I’ll also point out that we haven’t got there by lowering our guidance.

In fact, we have not lowered our guidance during this entire period, and that includes through the pandemic. So in summary, our strict adherence to our strategy, our commitment to an improving return on capital employed and extraordinary execution by our team, all have continued to deliver predictable growth through a variety of commodity cycles. Importantly, this discipline also has Williams position to capture significant future growth and return this value to our shareholders. And with that, I’m going to turn things over to John to walk us through the financial metrics of the quarter.

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.

Alan Armstrong: Okay. Well, thanks, John. So just a few closing remarks before we turn it over to your 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 amongst the S&P 500 and unique within our sector. Our natural gas focused strategy has allowed us to produce a ten-year track record of growing adjusted EBITDA through a record – through a large number of commodity and economic cycles.

And it is continuing to deliver significant growth in the current environment. And the signals coming from the market show that it is going to continue to deliver substantial growth well into the future. Shoring up our nations and the World’s Energy Foundation with natural gas is going to 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 it has become the practical alternative. Ramping up the production of natural gas has allowed 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 large number of government incentive electrical loads like carbon capture, hydrogen production and data centers is going to be largely 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. So we are here for the long haul and are committed to leveraging our large scale natural gas infrastructure network for the benefit of generations and our shareholders for generations to come. And with that, I’ll open it up for your questions.

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

Spiro Dounis: 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 maybe just provide a sense of how you think about the capital costs, maybe even the returns around the two phases of that project. And also if you could maybe 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 still seems like some level of confusion there.

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.

Spiro Dounis: Got it. Helpful color and appreciate the clarification on the EBIT contribution for that first phase. Second question, maybe just turning to these two DJ Basin acquisitions, 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 impute 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.

Alan Armstrong: Spiro, I’m going to have Chad Zamarin take that.

Chad Zamarin: Yes. Thanks, Spiro. So that 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. And Rocky Mountain Midstream has some excess capacity. So we’re going to be able to consolidate those volumes and move a significant amount of incremental NGLs down our infrastructure. But there are some dedications over the next 12 months and beyond that will roll off and that will allow us to move those volumes fully over to our system, so you’ll see that value increase over time.

Spiro Dounis: Got it. Helpful color. Thanks, Chad. Thanks everybody.

Chad Zamarin: Thank you.

Operator: Thank you. We’ll go next now to Neel Mitra at Bank of America.

Neel Mitra: 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 LEGpipeline. Are you seeing interest from Southeast customers rather Southern Utilitiesto move Haynesville gas on Transco towards that area?

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.

Michael Dunn: And Alan, probably important to note this is not a near-term macro. This macro setup is going to be 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’s going to continue to be a competition between utilities and LNG exporters for natural gas, and there is no better asset set up to benefit from that and provide the supplies that are needed than our footprint in the Transco system.

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?

Michael Dunn: Hey Neel, it’s Michael. Thanks for the question. Yes, the TLEP project is just awaiting at 7C [ph] permit. So we would expect that to be imminent. So we’re excited to get that one off the ground. And that’s really the first opportunity we’ve had to really increase our capacity from the South Texas area into the LNG corridor order on the other side of Houston. I would just tell you, we’ve got a lot of great opportunities to continue to expand that pathway on Transco. We have a lot of looping capabilities through that area, additional compression that we can add and really move a significant amount of gas to either South Texas or the Katy area over to that Texas, Louisiana coast line where the LNG facilities are being contemplated for expansion.

So really excited about those opportunities. We are talking to parties on both sides of that, whether it be a producer or a consumer of the gas on both sides of that opportunity. And the biggest impediment there is Houston, as you probably well know that the Transco pipeline system to reverse is just north of Houston there in that corridor, and we have one of the best quarters, we think, to expand from the west side of the Houston area over to the eastern LNG corridor.

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?

Michael Dunn: Yes. So right now, FERC has lowered their hurdle, I would say, for smaller projects like TLEP. So it was originally an environmental assessment and FERC basically came back and said, “No, we need any EIS and then they pivoted back and said, “No, this can go under an environmental assessment, which is a quicker process. You probably save six months to nine months on the environmental review typically between an EIS and an EA. And I would say any looping project of any magnitude is most likely going to take an environmental impact statement. And so that’s – whether it be a looping or a greenfield, it’s going to be an EIS, and that process is typically one and a half year to two years from filing to 7C approval.

So I would just say that’s the kind of the time line you should be thinking about for any type of looping project. I would say the looping projects are less controversial when you start talking to the environmental organizations and landowners just because we’ve obviously been in the area for a long time. We have relationships built in those areas and landowners are certainly much more receptive to a looping project than they are a greenfield type pipeline. And certainly, the environmental impact is less as well. And so I think you do have a better opportunity to get approvals for looping project because they’re just less controversial and FERC is very interested in condemnation authority in the use of that these days and it gives us a great benefit when we’re looking at looping projects just like our [indiscernible] project, we built 36 miles of loop along that pipeline and did not have one condemnation with several hundred landowners and it’s a great testament to what the brownfield expansion is going to do for our company.

Neel Mitra: Great. Thank you very much.

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

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?

Chad Zamarin: 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 been focused on bolt-on transactions that typically provide better than one or two turns of synergies and optimization. This is an integration that allows us to both increase gathering, processing, also we moved the NGLs down Overland Pass with our partnership with Targa, we can move the barrels all the way to Mont Belvieu, where we have interest fractionation. And so there’s a lot of opportunity to capture synergies along that value chain. So those are the kind of opportunities that we really look for that, provide very clear commercial and operational synergies.

So that’s really a focus. As far as additional opportunities, I think the Blue Racer example is another great one. We’ve been focused on cleaning up inefficiencies within our business. The team has been very successful, both within our commercial core dev and operating teams in finding opportunities to further take efficiency out of the business. And that’s actually the last of the non-operated joint ventures that we participate in. So we’ve made great progress and again, taking that kind of inefficient structure out of the business. And we’ll continue to look for opportunities to do that. And with the scale and geographic footprint like ours, these low-risk, high-value bolt-ons, I think, will continue to be opportunities.

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?

Chad Zamarin: Yes. I’d say it’s too early to really speculate the winner is just getting started. We’ve got – I mean, the great thing about the Sequent platform is it’s set up to be a very low risk platform, and we can sit and be opportunistic as weather events materialize. But at this point, we’re going to continue to remain cautious on kind of over-interpreting or trying to over predict the weather itself. And so we’re well set up well positioned for the winter, if we see dislocations. But remember that as that asset, that footprint is primarily structured for basis differentials and differentials in time and so we’ll continue to watch the weather play out. But right now, we feel pretty good how we’re set up.

Theresa Chen: Thank you.

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

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?

Alan Armstrong: No. Well, just to be clear, the agreements go – the clock starts on those agreements for 20 years when we place the expansion in service. And so that was the reference to 2047. I would say it’s pretty optimistic to think we would have that in service in 2027, certainly would be probably the latter part of that just timing standpoint. But that’s – obviously, we’ve set it up for permitting success, so we may be able to do that, but that was a reference to that. So it doesn’t – the timing doesn’t have any of those terms don’t have anything to do with Mountain Valley Pipeline. They are, many of those agreements are dependent on Mountain Valley Pipeline coming into service. But not under that timeline.

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.

Alan Armstrong: Yes. Sorry, Jean. I’m sorry, I didn’t understand your question. Yes. I would just say if that didn’t get done, I think it’s very low probability that over between now and 2027 that it wouldn’t be placed in service, but that’s what you’re suggesting, then we would probably have – those markets are going to have to have supplies from somewhere. And so we would have to come up with another way of getting those supplies to them, which would be a bigger project.

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.

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

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?

Alan Armstrong: Yes. Sure. Chad, do you want to take that?

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.

Jean Ann Saulsbury: Makes a lot of sense. Thank you.

Chad Zamarin: Thanks.

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

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.

Alan Armstrong: Yes. Well, first, I’ll take a high-level cut at that, and then John can provide some more detailed remarks on it. First of all, the base business is continuing to grow nicely. I think how much growth we see in the gathering business next year will be somewhat dependent on producers’ response. And obviously, their response will be somewhat dependent on both the prompt price as well as shape of the forward curve. And so a little bit of TBD, I would say, in terms of volume growth on the gathering systems and as that would affect our gathering revenues. I think on the transmission business, our opportunities there are acceleration of existing projects that we have out there. The team has been doing a great job like they did on REA of bringing that first phase in early.

So I think the opportunities there as you – if you look at our projects, most of those come in, including the big deepwater business comes on towards the end – very end of 2024. So some acceleration of those projects would be where the opportunities would exist on those very tangible and identifiable growth projects that drive a very large increase in 2025. So I think it’s a little bit early right now, frankly, to be calling what we’ll see from the producer community in 2024, and that will probably drive that on the margin. But I’ll let John take the more specifics on that.

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.

Brian Reynolds: Great. Thanks. Makes sense. Maybe as my follow-up, we’ve seen the market talk a lot about NGL and LNG opportunity sets over the next, call it, three years to five years with some downstream expansion opportunities. So I was kind of just curious, just given Williams strategic position on the transmission business, if you could just refresh us on your kind of $1 billion to $2 billion CapEx run rate or we could see some lumpy attractive projects ultimately move into the backlog and grow returns just given the thought process that we see 20 Bcf of natural gas demands coming over the next decade. Thanks.

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.

Brian Reynolds: Great. Super helpful. Hopefully some more returns like Southeast Supply. I’ll leave it there. Enjoy the rest of your morning.

Alan Armstrong: Thank you.

Operator: Thank you. We go next now to Jeremy Tonet at [indiscernible]. Jeremy, your line is open, if you do have a question at this time. Hearing no response. We’ll move next now to Tristan Richardson at Scotiabank.

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?

Alan Armstrong: Yes. It’s a great question, Tristan, and you picked up on an important point there. Our issue is that our customers, which are some of our best and biggest customers on Transco are their demands are very urgent. And for us to sit around and wait for – to finalize any more of the demand that was pending out there, really, it doesn’t serve those customers very well. And so we’re moving ahead with those customers that we’re ready to put binding contracts in place. And that – and we’re not – I would just say we’re going to try to protect that – the time line of that project. And that will be kind of first and foremost in our thinking as we move ahead on that. So could that expand a little bit where somebody else coming in under the wire before we do our pre-filing.

Yes, but I’d say, we’re not going to get ourselves strong out there in a way that we can’t move ahead with this initial project because our customers have made it very clear how important it is that we get on with it. So that kind of hopefully gives you a little bit of idea of what we’re dealing with there. But I would say it’s obvious from the open season and from the additional requirements that are continuing to service. I’d be just like I said earlier; I would be very surprised if we didn’t see another project come out of this. It’s just – we’ve got to get on with it because the demands are so.

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?

Alan Armstrong: Yes. I would just say, obviously, that’s a Board-level decision in terms of how we grow that dividend. I do think, as we’ve said all along, we do intend to continue to grow it in line earlier with our EBITDA and now with our AFFO just because we do have to make sure that we don’t ignore any tax liability that would start to affect that. And so that’s the reason for the switch from EBITDA to AFFO growth. But having said all that, I think the 5% to 7% is well within our wheelhouse and it certainly looks like that growth even as our EBITDA gets bigger, here for the next several years, at some point, the law of big numbers starts to overcome that. But for right now, I think the 5% to 7% growth rate is very achievable within our dividend growth rate.

Tristan Richardson: Appreciate it, Alan. Thanks all.

Operator: Thank you. We’ll go back next to Jeremy Tonet at JPMorgan. Excuse me.

Jeremy Tonet: Hi, can you hear me now?

Alan Armstrong: Yes. Got you, Jeremy.

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?

John Porter: Yes. Thanks, Jeremy. Thanks for the question. I mean I don’t think we really have any significant change to the returns-based approach that we’ve been discussing for capital allocation now for the last couple of years. We have seen a slight uptick in our borrowing costs, but we’re managing through that. I think very well. And of course, we’re seeing the returns on many of our projects as we’ve been discussing with that Southeast Supply enhancement being stronger than ever. So, I think the spread in our business between the returns on our invested capital and our cost of capital continues to be holding up very well, if not improving over time. I think as far as the capital allocation decision matrix that we’ve discussed in the past, as I know you’re familiar with, we are somewhat unique in terms of our ability to make fairly discretionary large investments into our regulated rate base and achieve regulated rates of return.

We do have a rate case coming up starting next year or so, we’ll be revisiting our ROE on our Transco rate base. And – but again, we do have a somewhat discretionary and somewhat unlimited ability to invest into that regulated rate base and achieve that regulated rate of return. So that really does set the floor of our capital allocation decisions. And I think going forward, you’ll see us, as we have done in the past, just monitor what we see as the return on share buybacks up against the potential to continue to make additional investments in the regulated rate base. And if we see dislocations in the stock price based on what we – what the current yield is trading at and our view of the growth into the future, then we’ll quickly act to buy shares as we’ve done in the past.

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.

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

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

Praneeth Satish: Thanks. I guess I’ll start with a high-level question, which is maybe touching on your prior remarks. Alan. But I guess, as you mentioned, there is pressure on offshore wind, even solar deployments under pressure under the higher rate environment. So I guess as you talk to your utility customers, have you observed any shift there in terms of their long-term perspectives on natural gas? And has there been any adjustments there in terms of their decarbonization time lines?

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.

Chad Zamarin: And I think it’s important to remember the fundamentals of the eastern third of the United States, and there are less than 10% intermittent resources today. So there is – they’re just getting started in deploying alternatives like solar and wind. And if you look at forecast for PJM it’s, I think, widely understood that by 2040 and this is long term. By 2040, peak gas demand is going to double from where it is today. And so the utilities have recognized that, one, they need gas here and now and long term in order to achieve decarbonization goals are going to need even more.

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?

Michael Dunn: Yes. This is Micheal. I’ll take that one. Thanks for the question. Yes, I would suspect if and when ONEOK gets the El Creek expansion done, we’d see less Bakken flows kind of a just they’ve been diverting some of the flows into the OPPL asset. We’ve got space and OPPL today to bring in the DJ volumes. So that’s really not a constraint as we see it today. But certainly, opening up more space is not a bad thing on OPPL ultimately, if we have the need to bring in more DJ volume. But we certainly enjoyed the volume from the Bakken to ONEOK has brought to our partnership.

Praneeth Satish: Got it. Thank you.

Operator: Thank you. And 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.

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.

Operator: 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 so much for joining us and wish you all a great day. Goodbye.