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Presentation

Operator: Good day, everyone, and welcome to The Williams Second Quarter 2023 Earnings Conference Call. Just a reminder, today’s call is being recorded. And now at this time, for opening remarks and introductions, I would like to turn the call over to Mr. Danilo Juvane, Vice President of Investor Relations, ESG, and Investment Analysis. 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 today are Michael Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you will find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. And these reconciliation schedules appear at the back of today’s presentation materials. So with that, I will turn it over to Alan Armstrong.

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Alan Armstrong: Okay. Well, thanks, Danilo, and thank you all for joining us today another positive story to share with you this quarter, and you can see some of those highlighted here and called out on Slide 2. First of all, adjusted EBITDA up 8%, adjusted earnings per share up 5%, and our gathering volumes were up 6%. And certainly, while this growth and beat is impressive, our resiliency in the face of low commodity prices is even more impressive and gave us another opportunity to distinguish ourselves from the pack, which is largely post to declines this quarter. And our growth continues to compound despite these price swings in natural gas. This quarter was a perfect example where we saw an 8% EBITDA increase on the back of a very strong 14% increase for the same period last year.

John will dive deeper into the numbers in a moment, but let me start out with a few highlights from the quarter. Our financial performance is our track record, but it is the day-to-day focus on execution by our teams that drives these results and really does set us apart. As an example, our teams have done a fantastic job of quickly integrating the MountainWest acquisition into our core business, and in fact, we’re pleased to announce that we’ve already secured binding precedent agreements to support a significant expansion on the newly acquired Overthrust Pipeline. This project was not even in our upside case for this investment, and the team has identified even more growth to come that is beyond our original expectations. Much of this growth is centered around coal to natural gas conversions in the western states.

On Transco, we continue to advance our emission reduction program and recently completing – completed our first large scale compressor replacement project in Virginia, our backlog of high return pipeline expansion opportunities continues to progress driven by a large wave of incremental demand that continues to exceed our expectations. As evidence of this continued wave of increasing demand, we recently concluded a non-binding open season to advance another large scale Transco project that will provide much needed capacity to serve our customers South of Station 165 in Virginia. Our customers recent – customers requested capacity that has been well in excess of the 800,000 dekatherms per day that we offered. Importantly, the minimum required term for this service offering was 20 years.

This underscores our belief in the durable and fast growing demand for capacity and the market’s confidence in our ability to deliver this capacity with the lowest environmental impact. Following the approval of the Mountain Valley Pipeline. We’re now working to find a way to serve as much of our customers’ needs as possible and hope to have an update on this exciting project soon. Moving on to financial performance, as I stated earlier, despite a weakened natural gas price environment, our financial results not only grew against a difficult comp in a difficult environment, but this quarter marked the 30th consecutive earnings print that either met or exceeded consensus estimates. Within our legacy based business in the Northeast, we produced record EBITDA and record gathering volumes delivering growth that far outpaced the total production across Marcellus.

Our strategy to focus on connecting our producing customers to the best markets with the most reliable service available has grown this business to the point it is nearing $2 billion per year of EBITDA. The completion of the Mountain Valley Pipeline, our Regional Energy Access project and continued growth of gas-fired generation in the local market will continue to provide market and volume growth well into the future. In the West, we also achieve record gathering volumes once again showing that our diverse geographic position is built to weather commodity price swings. In our transmission in Gulf of Mexico segment, we are enjoying the beginnings of a long runway of growth in the deepwater gearing up for a long string of expansions on Transco and enjoying better than expected growth in our MountainWest acquisition, which speaks to our successful integration.

Importantly, the strength of our base business more than offset weaker E&P earnings and expected low seasonal cash flows from our marketing business. The quarter’s results continue to prove out the inherent stability and stubborn growth of our business. However, when we see the market fail to appreciate our ability to deliver in most price environments, we will continue to execute on our authorized repurchase program much like we did during the second quarter. And finally, a few notes on our sustainability efforts. Last week, we issued our 2022 sustainability report and completed our annual CDP Climate Questionnaire. These are both important markers that detail our progress on key issues like environmental stewardship, community sport, and workforce development.

To us, sustainability means running our business in a way that will create value for the perpetual shareholder. So we’re proud to have also be providing our shareholders with industry-leading returns on invested capital, and we expect our shareholders to further benefit from enhanced capital returns as we execute on our large growth backlog, which among others include seven out of nine major pipeline projects that are coming online in the fourth quarter of 2024 and that will be stacked on top of a solid foundation of a sustainable based business. And with that, I’m going to turn things over to John to walk us through the financial metrics of the quarter. John?

John Porter: Thanks, Alan. Starting here on Slide 3 with a summary of our year-over-year financial performance, beginning with adjusted EBITDA, we saw another strong quarterly increase of 8% over the prior year, and this happens to coincide with an 8.6% CAGR over the last five years for this same measure. And this strong performance included a new record for gathering volumes, which increase 6%. Year-to-date, our adjusted EBITDA is now up 13% driven by the growth of our core infrastructure businesses, which continue to perform very well, even as natural gas price decreased 61% for the first half of 2023 versus the first half of 2022, once again, demonstrating the resiliency and strength of our natural gas focused strategy, our assets, and our operational capabilities.

For second quarter, our adjusted EPS increased 5% for the quarter, continuing the strong growth we’ve had in EPS over the last many years with our year-to-date EPS now up 23%. Available funds from operations AFFO growth for second quarter was in line with adjusted EBITDA and you see our second quarter dividend coverage based on AFFO was a very strong 2.23 times growing about 2% despite growing our dividend by 5.3%. Our balance sheet continues to strengthen with debt to adjusted EBITDA now reaching 3.5 times versus last year’s 3.82 times and that’s even after closing the Trace, NorTex and MountainWest acquisitions and also repurchasing $139 million worth of shares since last year. On CapEx, you see an increase primarily reflecting the progress we’re making on some of our key growth projects, including Regional Energy Access and Louisiana Energy Gateway.

For the full year, there’s no change to our consolidated adjusted EBITDA guidance of $6.4 billion to $6.8 billion or any of our other guidance metrics. But in a moment, I’ll provide a little color on our expectations for the remainder of the year versus the performance we’ve seen thus far in 2023. So let’s turn to the next slide and take a little closer look at the second quarter results. A strong 8% increase in EBITDA over prior year even as average natural gas prices for the second quarter decreased 71% walking now from last year’s roughly $1.5 billion to this year’s $1.6 billion, we start with our Upstream joint venture operations that are included in our other segment, which were down $43 million versus last year. Our Haynesville Upstream EBITDA was down about $14 million despite substantially higher production due to much lower net realized prices and a lower working interest percentage on new wells beginning in January of 2023.

Our Wamsutter upstream EBITDA was down $29 million due primarily to lower realized prices, but production also continued to be impacted throughout April from the historically difficult Wyoming winter weather we saw in the first quarter. Shifting now to our core business performance, our transmission in Gulf of Mexico business improved $96 million or 15%, including about a $52 million contribution from our MountainWest Pipeline and NorTex acquisitions, but with other increases in our transmission and deepwater revenues as well. Our Northeast G&P business performed extremely well with a $65 million or 14% increase, driven by an $81 million increase in service revenues. And we did have a one-time $14 million favorable gathering revenue catch up adjustment in that second quarter increase in service revenue.

But this revenue increase was really fueled by a 6% increase in total volumes in the Northeast. Shifting now to the west, which increased to $16 million or 5%, benefiting from continued strong volume growth in the Haynesville and positive hedge results that partially offset the impact of lower commodity base rates. And then you see the $22 million decrease in our Gas and NGL Marketing business and the majority of this decline was actually related to lower NGL marketing results from inventory valuation changes where we had to gain on NGL inventories last year at a loss this year. So again, the second quarter continued our strong start to 2023 with 8% growth in EBITDA driven by core infrastructure business performance in spite of natural gas prices that were 71% lower than second quarter of 2022.

So let’s turn the page and touch on the year-to-date comparison. Year-to-date, we’ve seen a 13% increase over 2022, walking now from last year’s $3 billion to this year’s $3.4 billion, we start with the upstream joint venture operations included in our other segment, which were down $39 million versus last year. Now, year-to-date, Haynesville is up nicely on very strong volume growth that has been significantly offset by lower realized prices. However, the overall Haynesville increase was offset by lower Wamsutter results due primarily to the historically difficult winter weather we saw in Wyoming this year. Shifting now to our core business performance, transmission in Gulf of Mexico business improved $127 million or 9% that’s really similar themes as our second quarter, namely the impacts of the MountainWest Pipeline and NorTex acquisitions, however, we have seen other significant increases in our transmission and deepwater revenues as well.

Our Northeast G&P business has performed very well with $117 million or 13% increase driven by $154 million increase in service revenue. This revenue increase was fueled by a 7% increase in total volumes focused in our liquids rich areas where we tend to have higher per unit margin than our dry gas areas. And in the appendix, you’ll find a slide that compares our 7% volume growth to the overall basin growth of just under 2%. Shifting now to the West, which increased $42 million or 8%, benefiting from positive hedge results and the Trace acquisition, but the West was significantly unfavorably impacted by the severe Wyoming weather and January processing economics at our Opal Wyoming processing plant. And then you see the $144 million increase in our Gas and NGL Marketing business caused by the strong first quarter that we had at the start of the year.

So again, a continuation to the strong start to 2023 with 13% growth in EBITDA, driven by core infrastructure business performance with strength from our marketing business that dramatically overcame weaker than expected results from the upstream joint ventures. So as I mentioned earlier, there’s no change to our consolidated adjusted EBITDA guidance of $6.4 billion to $6.8 billion or any of our other guidance metrics. We’ve definitely had a strong start to the year with $3.4 billion of EBITDA through the first half of the year. And thanks to the performance of our base business we have clear visibility to hitting at least the mid-point of our guidance even after a historic decline in natural gas prices and a historically difficult winter that continue to have impacts through April.

So you may be wondering, why we aren’t raising our guidance on the back of such a strong start to the year and a bright future ahead. First, I will remind you that our guidance does include a range of $200 million above our midpoint. And second, while we usually experience stronger third and fourth quarters than second quarter, the third quarter does occasionally see hurricane outages for our deepwater business. Finally, we could also still see downward shifts in natural gas prices for the balance of the year that could unfavorably impact our upstream joint ventures in particular. While we are not suggesting, there is a high likelihood of realizing these impacts, we do need to be prepared to overcome these scenarios. Therefore, it is too early to raise our full year guidance.

But once again, we are confident in the continued performance of our base infrastructure businesses, allowing us to once again meet or exceed the midpoint of our guidance range. We’re setting our sites on continued growth in 2024 before another big growth step in 2025. And with that, I’ll turn it back to Alan.

Alan Armstrong: Okay. Thanks, John. Just a few closing remarks before we open it up for your questions here. 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 integrated nature of our business from our best-in-class long haul pipes to our formidable gathering assets, which are complimented by our Sequent platform that delivers upside to our base business is unique and we have a track record to prove it. Second, our combination of proven resilience, five year EPS CAGR of 23%, industry leading coverage on our steadily growing dividend, a strong balance sheet and high visibility to growth we think is unique amongst the S&P 500 and unique within our sector.

Let me emphasize that our natural gas focused strategy has allowed us to produce a 10-year track record of growing adjusted EBITDA through a number of commodity and economic cycles. And it is continuing to deliver significant growth in the current environment. And we’re now celebrating 7.5 years of delivering inline or better quarterly results. That is especially impressive when you consider the sectors ups and downs over this period. And the fundamentals are setting up stronger than ever for this long-term predictable growth to continue. And finally, as we think about our long-term strategy, we see that U.S. natural gas infrastructure is key to meeting both today’s energy demand as well as projected growth of electrification and renewables build out in the future.

Simply put, you cannot implement and accelerate wind, solar and large scale electrification without having natural gas as a reliable complimentary partner to these big system changes. In fact, despite continued growth in solar and wind capacity, the country saw record natural gas power demand in July, reaching as high as 53 Bcf per day last week to meet summer power loads. This tops the previous record set last July by 6%, again, compounding growth on top of compounding growth. And so if we truly do want to meet our country’s growing power demand for things like data centers and EVs and accelerate wind and solar power generation, we must continue increasing natural gas infrastructure capacity. This fact has become evident to both the majority of our legislators and the Biden administration as they came out with unprecedented support for Mountain Valley Pipeline’s completion.

Williams is here for the long haul and we are committed to leveraging our large scale natural gas infrastructure network for the benefit of generations to come. And with that, I’ll open it up for your questions.

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

Spiro Dounis: Thanks, operator. Good morning, team. First question, maybe start with gas macro. Looks like, we’re maybe approaching a trough here and some of the producer activity. So just curious to get your all’s view on what your producer customers are seeing and doing and really just how you’re thinking about the volume and price trajectory from here as we head into 2024 and really wait for LNG volumes to pick up a lot of the slack.

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

Spiro Dounis: Yes. It’s helpful. Second question is maybe moving to leverage as you guys pointed out, you’re down to about 3.5 times now this quarter, so already below your target on the year. So just curious how you’re thinking about utilizing this excess balancing capacity. Is that the plan or really maybe even thinking about operating at these lower levels?

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

And so anyway, I would just say to answer your question more directly, we have places to place capital for nice return like that and I think we’ll continue to do that, but we certainly enjoy the flexibility that we have at this level to be able to place capital towards those kinds of opportunities.

Spiro Dounis: Great. I’ll leave it there. Thanks for the time guys.

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

Jeremy Tonet: Hi, good morning.

Alan Armstrong: Good morning, Jeremy.

Jeremy Tonet: Just wanted to start off with Appalachia, if I could Northeast G&P quite a good quarter there, recognize there’s a little bit of timing with the revenue catch up there. But just wondering if you could talk a bit more about what’s a normalized EBITDA level in the Northeast G&P right now. And are you seeing kind of a shift in production wet versus dry and is that impacting margins, just trying to get a bit of color for what the trajectory is here?

Alan Armstrong: Yes. I definitely think we saw producers focusing, where they have it available. We saw producers focusing on wet where there are producers that have that ability to shift. But while at the same time, I think keeping themselves poised for markets to open up. And so I would say, that’s kind of what we’ve seen. In terms of normalized EBITDA, I think the first two quarters are a pretty good sign of that. I think anytime you can just average that out over a couple of quarters, I think that’s a pretty good sign of a normalized number. But I do think as markets open up through both MountainWest and Regional Energy Access and continued industrial and power generation demand in the local markets, I think we’re going to see that PJM, certainly found itself very short power lasts year or – and during the winter time as well.

And I think we’re going to continue to see people build out power generation to take advantage of that. So I’m pretty encouraged, frankly, about in terms of the market outlook over the next couple of years for the Northeast. I do think that we’ll see the Northeast have an opportunity to take back some of the market share across the U.S. as a result of some of these markets opening up.

Jeremy Tonet: That’s very helpful. And just to clarify, when you say new markets opening up, is this regional energy that kind of prime in the [indiscernible] or MVP or others?

Alan Armstrong: Well, there’s really three distinct issues there. Mountain Valley Pipeline certainly, and it’ll be competing. There’s been some confusion out there. I think in the market, we have plenty of capacity to pull all that MountainWest can deliver. It’s just a question of how it’s going to compete with Haynesville gas coming in at Station 85 on the system. And so there – but there’s – it’s just going to be a question of producers competing for those markets. But I will say that market in particularly at south of Station 165, as was demonstrated by a recent open season is going to continue to grow pretty rapidly. And last winter got caught in a very short situation on natural gas. And so we’re going to continue to see the markets in the Carolinas there and Virginia and the Southeast continue to expand.

Mountain Valley Pipeline’s going to be that connection. In addition to that Regional Energy Access is also going to provide new market and that’ll take some time. It’s not going to be a snap your fingers and we’ll see that kind of growth pulled out of that area, but it will open up new markets and new demand. And then finally, as I mentioned, regional loads in the area as well and people taking advantage of low price natural gas, and in fact, the shell big cracker there is just one good example of the industry growth, but as well we’re seeing power generation load to continue to build there as well in the PJM area. So I think really pretty clear examples of market growth for the Northeast.

Jeremy Tonet: Got it. Very helpful. And just one more on gas, if I could. I think in our stakeholder conversations across various states, we’re starting to see gas peakers come back into integrated resource planning that we had not seen in recent years or maybe had fallen out in recent years. And just wondering if you’re seeing this trend as well, particularly as it relates to Transco and its unique positioning? And could this lead to incremental opportunities beyond kind of what’s in the slides today?

Alan Armstrong: Yes. I think as we mentioned, the open season that we had for capacity south of 165 really kind of caught our attention, frankly, and far exceeded our expectations. And so when we say that it exceeded what we had to offer, it was a very large multiple versus what we had to offer there. So yes, we definitely are seeing the signs of people taking advantage of low price natural gas. And importantly, I think this is something that gets missed too often, Jeremy, I know you follow this, but I think sometimes the broader investor base misses this that – what we have to sell is capacity. It doesn’t mean that that’s going to be an annual average increase in volume as much as it does mean that people are absolutely going to have to buy capacity for those peakers and for baseload.

And we actually, I think we’re going to see quite a bit of baseload pick up as well, because the amount of data centers, the amount of electrification load that’s going on is well in excess of what our increasing wind and solar generation can keep up with. And so we’re not only going to see peaking, we’re going to see baseload increase as well. But again, all of that boils down, whether it’s peaking or it’s baseload, people still have to buy the full amount of capacity on our pipeline. And that’s certainly coming through in these open seasons that we’ve been having on – in that area.

Jeremy Tonet: Got it. Right. Makes sense. Coal to gas baseload conversion clearly there, but the peaking needs – I think it seems a bit underappreciated. So very helpful color. Thank you for that.

Alan Armstrong: Thank you.

Operator: Thank you. We’ll go next now to Jean Ann Salisbury at Bernstein.

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

Alan Armstrong: Well, also Jean Ann, you have to realize I think we have six projects along that exist, along that corridor or five along that corridor, excluding Regional Energy Access that are also expansions in that same area that were not dependent on Mountain Valley Pipeline supplies coming into that area. And so there’s a number of projects that and we got them listed there in our materials. So that is – obviously those come on before this latest open season would, but those are increments to serve increasing demand for power generation in the Virginia, North Carolina, South Carolina and Georgia areas.

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

Alan Armstrong: Well, yes, the point I think that’s misunderstood, Jean Ann, is that we have the physical capacity to move that gas from Station 165 period into sentence and not very complicated. We have plenty of capacity to move from that point. The piece I think that got missed by some of the market consultants was the fact that the – how much would actually move from that point, because people are already buying supplies from Station 180 – or sorry, Station 85 and moving it north, but those same shippers have the ability to pick their gas up at 165 if they choose to. So it’s just going to be a matter of where they decide to pick their gas. But we have plenty of capacity to move gas out of station, the 2 Bcf a day out of 165.

So the physical capacity exists, the shippers actually are the ones that decide how we operate the system and where we move the gas from. And if they decide, they want to buy it at 165, 85 will get backed off and 165 will get picked up for supplies.

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

Michael Dunn: Hey, Jean Ann, this is Michael. Some of that was Bakken volumes coming in on the OPPL line from a third-party as well as some methane volumes that picked up in the quarter.

Jean Ann Salisbury: Great. That’s all for me. Thank you.

Alan Armstrong: Thanks, Jean Ann.

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

Brian Reynolds: Hi. Good morning, everyone. Maybe to start off in the 2023 outlook, John, you talked in the prepared remarks about year-to-date outperformance, which supports at least the midpoint. But just kind of curious if you can give some commentary around, uncertainty around these hurricanes in nat gas pricing. Is that baked in to your confidence over the midpoint and thus just assuming constructive or normalized second half fundamentals, just kind of curious if you could sensitize the upper end of the range as well. Thanks.

John Porter: Yes. I think we want to have a lot of confidence in hitting our midpoint. So we do account for things that could happen around the hurricane season and perhaps additional weakness that could come, as I mentioned, from a further decline in natural gas prices. So we’ve built in some ability to handle those kinds of downsides relative to making sure that we can hit our midpoint. So I think conversely, the things that would move us higher in the range would just be better than forecasted performance in the underlying gathering and processing systems in the base business, which is always possible. And it is also possible that we could have a stronger marketing result in the fourth quarter. Sometimes we have fairly strong for example, Novembers and Decembers, but that is unpredictable.

Most of that performance comes in the first quarter. So we don’t like to overly depend on any kind of a marketing result to make the numbers. And so we got a lot of confidence just from the base business around hitting the midpoint of our guidance and certainly think we could exceed it as well, but still fairly early in the year and just weren’t comfortable yet in raising the guidance.

Brian Reynolds: Great. I appreciate…

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

Brian Reynolds: Appreciate that. That makes a lot of sense. As my follow-up, great to see the environmental assessment for the Texas to Louisiana Energy Pathway Project to bring nat gas from Texas into the Louisiana border. LNG demand continues to be a theme, particularly on gas E&P calls this quarter. So just kind of curious if you could just discuss perhaps further greenfield opportunities beyond TLEP that Williams could pursue to bring even more natural gas from Texas across to LNG to support that future demand. Thanks.

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

Brian Reynolds: Great. Makes sense. We’ll leave it there. Enjoy the rest of your morning. Thanks.

Alan Armstrong: Thanks, Brian.

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

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

Michael Dunn: Hi, good morning, Praneeth. This is Michael. Yes, the open season results were a pleasant surprise and we’re currently working through the scenarios with the various customers that requested capacity there. It definitely can be upsized from the 800,000 to be published in the open season notice and we’re just working through that today. So hopefully, we’ll have some more information on that in the very near future in regard to the outcome of those negotiations. But it’s really just a combination of looping and compression additions alongside our brownfield Transco pipeline corridor. And it’s just getting the hydraulic modeling done and developing the proper scenarios and then ultimately giving the rates to the customers that would be identified by the looping and compression on those scenarios.

So it’s a little bit of an iterative process, which we’re going through right now, but it can definitely be upside from the 800,000 a day. I’d say the schedule, right now, a lot of that’s driven by the customer’s desired in service date. And so a lot of this capacity is for new gas-fired power generation and anticipating when those new power plants come online is the expectation that the customer’s laying out there for us. I do think there may be an opportunity to accelerate the project at some point, but obviously we have to have customer agreements in place before we can start designing the desired schedule for the customers as well as our capital cash flow. So that’s really what we’re looking at right now. I think 2027 is probably the outside date that we’d be looking at and we’ll try to pull that in where we can.

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

Michael Dunn: Yes, absolutely. The Sequent has a very large storage portfolio. I don’t know that we’ve actually disclosed the aggregate size of it is, but it is a very large storage portfolio and we would expect them to be able to lock in the intrinsic value of that storage. And they also have a lot of deliverability capabilities out of that storage and can optimize around that storage position as well. I don’t think we’ve given a lot of the specifics about the aggregate size of that storage position, but it is a strong storage position that we would expect them to be able to lock in a lot of value around.

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

Praneeth Satish: Got it. Thank you.

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

Colton Bean: Good morning. I was just following up on the question on the Northeast saw it’s pretty significant sequential increase in G&P revenue. I know you mentioned the $14 million benefit from a catch up payment there. But even after adjusting for that, it seems like the year-on-year increase is still well above what we would’ve expected from inflation escalators alone. So I guess, are there any other contractual provisions that are pushing unit rates higher across the basin there?

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

Colton Bean: Okay. And that’s primarily showing up in gathering I think on a processing basis volumes looked pretty consistent.

Alan Armstrong: Yes. Right.

Colton Bean: Got it. Okay. And then two related questions on cost control. I think if we look at the transmission segment, it looks like OpEx is roughly flat to your pre-acquisition levels after adjusting for the transaction expenses there. So you seeing MountainWest synergies materialize earlier than expected, or should we expect some degree of cost increase moving forward? And then just more broadly, it looks like pretty impressive cost control across all segments expenses flat to down on a year-over-year basis. So if you could just comment more broadly on your cost control initiatives and expectations through the balance of the year.

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

Colton Bean: Great. Thank you.

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

Neel Mitra: Hi, thanks for taking my question. I wanted to clarify on Jean Ann’s question, the available capacity on Transco. So if I understood it right, are you saying that there’s available capacity on Transco from MVP if you were to back off volumes from Zone 4? So it essentially would be shifting volumes from one area to another to accommodate the existing utility demand. And then I guess the follow on to that would be to accommodate new growth and new demand from utilities, there would need to be Transco expansions. Am I thinking about that the right way?

Alan Armstrong: Yes. Neel, let me try explain it one more time. The way the most of the system rates work on there, the shippers have pay the same price, they pay us no matter where the gas is moving from. Generally the – those utilities in that corridor have the ability to pick up gas and they have a volume available that they can pull from at various receipt points. And so they basically are out trying to buy the lowest price gas on the system that they can have delivered into their meters every day. And when we talk about system capacities, we’re actually talking about kind of the delivery capacity to those locations, and it’s – this particular path that somebody buys capacity from on the system. But the big long haul system and the original base system, the shippers have the ability to choose where they want to pull their supply in from.

And so even if they’re – we have a number of expansions going on, but even if you just looked at it in a static environment, if somebody today was buying gas Station 85, that gas is likely coming in from either system gas on in the Offshore or Haynesville or gas that’s made its way in from the Permian. But Station 85 or 65 would be a place that customers would be nominating their supplies from and they’d be buying gas from maybe a Haynesville producer at Station 85. If they – if somebody from the Marcellus decides, they want to sell their gas cheaper at 165, then that customer’s going to be able to say, well, I’m going to nominate from Station 165 – at the 165 location instead of 85. Same amount of gas eventually flows to their delivery point.

But it’s just a matter of where they source their supply from. So in – so we – it’s just going to be a question of where producers decide to sell their gas set and who wants to compete the most for those supplies. As we build out the system and the demand then matches back up to that supply then the system would be back in balance. And – but that’s the way it always worked. There’s always periods where supply builds up because you have more supply locations, then you have delivery, and then eventually you build out the delivery market like we’re doing in all these projects. And then more supply is needed, which is kind of the situation at Station – sorry, at Zone 5 right now. People got caught short there in the winter because there was not enough supply coming in there.

So MVP will provide that needed supply that was missing this last winter.

Neel Mitra: Yes. I think maybe the confusion is whether if all things are static and you didn’t back anything off of Zone 4, how much could you move South on Transco down from Zone 165 with the MVP volumes that are coming in?

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

Neel Mitra: Got it, got it. Okay. Perfect. Thank you.

Alan Armstrong: Thank you.

Operator: We’ll go next now to Tristan Richardson of Scotiabank.

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

Alan Armstrong: Yes. Good question, Tristan. I would just say we were really pleased with multiple, we were able to pick up the MountainWest assets pretty seldom that you get assets that are – that well contracted that have that much growth around them, which frankly has been more than we even expected. Pretty rare to see that kind of multiple. I think that the issue there that kind of dampen the market was the concerns over Hart-Scott-Rodino that had been raised earlier in the Berkshire Hathaway and Dominion transaction that involved those assets. And I think that had the market a little bit spooked on that. So maybe that’s why we were able to bridge over that in that case. But yes, so I would say, we’re going to keep looking for those anomalies like that and where we have confidence in our ability to add value to assets.

But I think it’s going to be rare circumstances that we see those kind of multiple. There’s usually a reason in this case, I think a lot of the issue was the risk around Hart-Scott-Rodino that it already surfaced itself on those assets earlier.

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

Alan Armstrong: Mike, do you want to take that?

Michael Dunn: Yes. Tristan that was not in our pro forma economics for the acquisition. So it’s certainly a pleasant upside there with the MountainWest acquisition. This is about an 11% increase in the Overthrust capacity for the 325,000 dekatherms a day expansion. And it’s a pretty simple expansion. It is two compressors that we’re adding at existing compression facilities on that system, but there’s definitely more upside opportunity there. There seems to be a desire to get more gas Westbound toward the Opal pricing point. That’s been a pretty solid pricing point for a number of years now. And even this summer, we’ve seen gas trading at $4 there at the Opal hub, even higher than that, just driven by California economics with the heat that hits California this summer and gas generation that’s picking up there.

So I would expect to see a lot of desire for customers to get to that Opal pricing point. And that certainly bodes well for Overthrust at the direct connection into that hub. And as far as the rest of the MountainWest system, we see a lot of opportunity there for coal to gas switching. There’s a number of very large coal-fired power plants in Wyoming and Utah that do have opportunities for conversion to natural gas. And some of those we’ve already acquired and we’re actually building expansions for off the Overthrust system today in Bridger Units 1 and 2 in Wyoming on the [indiscernible] system are converting to gas. And we’re building a pipeline over to the – that facility this year. So we’ll continue to see opportunities like that on the MountainWest system and those are certainly upside opportunities, not only for us, but gas will be sourced out of the Wamsutter field with our Upstream production and we’re driving that gas to those markets as well with the secret platform.

Tristan Richardson: That’s great. Appreciate it. Thank you, Mike.

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

Gabriel Moreen: Hey, good morning, everyone. It looks like you had a lot of E&P hedges since your last update in 1Q. I was just wondering if you can not to beat a dead horse on 2023 guidance, which I know I’m doing, but just what the exposure is at this point on the E&P side, and then also as you think about hedging 2024 for on the E&P side, which what you’re thinking, and maybe in light of also potentially doing some transactions around E&P with the gas curve having creeped up a little bit here.

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

John Porter: Yes. Absolutely. We have continued to add hedges on the expected Upstream JV production. We generally don’t go too far in hedging. We like to have a comfortable spread between what’s hedged and what’s not hedged, just to account for the potential for any kind of production offset. So there is a fairly significant portion that that remains unhedged. We do provide in our materials all of the current hedges that we have outstanding against the Upstream business and that’s in the appendix.

Alan Armstrong: Yes. And Gabe, I would just add to that, I think in terms of our approach to hedging on the E&P side, we have been putting on some April through October hedges for gas in 2024. And as John said, large – so part of that’s driven by the fact that we don’t really want to get caught short in an up market. I think everybody experienced that a couple of years ago. And so we tend to not get ourselves in a position where we could get caught short on production, particularly since we don’t operate that production. So that’s how we think about hedging on the E&P side there. So – but in terms of the – in the broader scheme of things, in terms of transactions around E&P, I would just say we continue to entertain a lot of interest in that.

And I would just say I – as we look at the landscape and the demand that’s building for not just – everybody’s very focused on LNG and we think obviously that’s going to continue to be a big driver for demand, but the macro picture we’re seeing around electrification and the amount of power demand increase that continues to build in this country is pretty impressive. And we’re also seeing a lot of industrial demand pick up in and around our assets as well, and things that were previously powered by either fuel oil or coal or onshoring ammonia production here in the U.S. there’s just a lot of demand building and we have a pretty good insight to that. So it’s kind of seems shortsighted to get in a hurry to sell out particularly at like the Haynesville where the team, the GeoSouthern team has done a great job there and they continue to find ways to lower cost and increase production there.

So we think both from their operational capabilities, which we’re enjoying and the macro fundamentals around gas is just not really a compelling reason to liquidate in this environment.

Gabriel Moreen: Thanks, Alan. And then maybe if I can just ask a follow-up on the ERP spend at Transco, and I recognize it’s – Transco’s got an awfully big rate base to it, but as you think about having to file the rate case at Transco and its upcoming, how do you think about ERP spend within that context? Does it matter at all with the rate case coming up as far as accelerating it or refraining from doing that?

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

But obviously hoping to go into this one with an emissions tracker, modernization type tracker coming out of the negotiated settlement that we hope to achieve with the Transco customers and we’ll see how that turns out.

Gabriel Moreen: Got it. Thanks, Michael.

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

Jake Nivasch: Hi, this is Jake Nivasch on for Neal. Just a quick one on cap allocation. I think you guys might have covered it, but I just want to make sure that I heard it correctly. Just in regards to distribution growth, I mean, you guys are pretty well covered even after that 5% boost this year. Are you looking – and you might have covered this already, but are you looking to accelerate that at some point in the near-term? Or just curious how you guys are thinking about that?

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

Jake Nivasch: Got you. Okay. That’s it for me. Thank you.

Alan Armstrong: Thank you.

Operator: And we’ll go next now to Robert Catellier at CIBC Capital Markets.

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

Alan Armstrong: Yes. I would say that that’s not completely clear to us yet. It’s a good question and you would think it would ultimately have some impact, particularly people that are exposed to floating rates that, that, that certainly would drive some transactions. But I would say we haven’t seen great evidence of that occurring just yet. And I would just say we’re going to be like we have been hanging around the hoop looking for things where we have a unique competitive advantage that drives really strong accretion and value to our shareholders. And so far that patience has paid off really well for us. And I don’t see any reason we would change that patience to keep kind of looking for those things that are very unique and that we have a unique competitive advantage on.

And so that’s what I would tell you to expect more of, but I’m not sure that, that I yet see the market being flooded or depressed with assets yet from people that might be sitting on floating rate capitalization. So we’re very fortunate where we stand from both a debt capacity and an interest rate standpoint without floating rate exposure. So we’re really excited about where we stand, but there may be some businesses and assets that get a little bit damaged and have to look for transactions to solve their problems, but that’s not evident to us just yet.

Robert Catellier: Okay. That was the color I was looking for. Thank you.

Operator: Thank you. We do have no further questions this morning. Mr. Armstrong, I’d like to turn things back to you for closing comments.

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

Operator: Thank you again. Ladies and gentlemen, I will conclude The Williams second quarter 2023 earnings conference call. I’d like to thank you all so much for joining us and wish you all a great day. Goodbye.