Q3 2023 The Williams Companies Inc Earnings Call
Please standby were about to begin.
Good morning, ladies and gentlemen, and 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. At this time I will turn things over to Mr Technology Bonnie.
President of Investor Relations. Please go ahead Sir.
Thanks, Paul and good morning, everyone. Thank you for joining us and for your interest in the Williams companies yesterday afternoon, We released our earnings press release, and the presentation that our president and CEO, Alan Armstrong and our Chief Financial Officer, John quarter can speak to this morning.
Also joining us on the call from Micheal Dunn, our Chief operating Officer Lane Wilson, Our General Counsel and Chad <unk>, our executive Vice President of corporate strategic development.
In our presentation materials, you'll find a disclaimer related to forward looking statements.
This disclaimer is important and integral to our remarks and you should review it.
Also included in our presentation materials are non-GAAP measures that we've reconciled to generally accepted accounting principles and.
And these reconciliation schedules appear at the back of the data presentation materials.
With that I'll turn it over to Alan Armstrong, Alright, 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 our Transco as 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 result 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 enabled our newly acquired more text 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 <unk> gathering system in the Haynesville for Geo Southern which I'm proud to say was the nation's fastest growing gas producer to last year and in the northeast. We completed the first expansion of many to come on our Cardinal gathering system for <unk>.
Rich gas drilling operations in the Utica condensate window.
But the really Big news. This quarter is comes in the new projects. We recently signed precedent agreements of over one four Bcf a day for the southeast supply enhancement project, which provides takeaway capacity from station 106 from our Transco station 165 to the fast growing mid Atlantic and southeast.
<unk>.
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 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.
And 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 contract from the time the project starts up which would be at least through 2047.
And we recently signed anchor shipper precedent agreements for our Uinta basin expansion on our mountain West system. We continue to be very pleased with the successful integration of the mountain west assets into our operations and the opportunities we see to execute on more profitable growth with this asset than we had originally planned.
In fact this is the second piece of substantial business that we have signed up just this year.
The mountain West pipelines.
And neither of which of these expansions neither of these were in our pro forma for this acquisition, so really pleased with that.
The team from mountain West pipeline and the leadership, we have working to.
So that business, but very pleasantly surprised with that acquisition to date.
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 our recent legal judgment will help fund an important strengthening of our hand in the DJ basin with the following transactions.
The acquisition of procured and front range LLC, whose assets include gas gathering pipeline and two processing plant to serve producers across 225000 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.
<unk> results in us now owning 100% of that so KKR as 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 relationships, we have 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 volumes into our downstream assets in <unk>.
<unk>, 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 $2 7 billion and this represents a blended multiple of approximately seven times the 24 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 transfer that coupon clipping on the downstream NGL transportation fractionation and storage.
These are the transactions are expected to close by the end of 'twenty, three making Williams the third largest gatherer 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 operator ship 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.
And lastly, we are continuing to advance our efforts to commercialize clean hydrogen through are supportive to 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 a right of ways and of 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 2002.
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 2002.
And we expect this strong performance to continue providing us with the confidence to raise our 'twenty three 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 EBITDAR consensus and the fifth time, we have raised guidance during the same period and I'll also point out that we haven't gotten there by low.
During our guidance in fact, we have not lowered our guidance during 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.
An extraordinary execution by our team all have continued to deliver predictable growth through a variety of commodity cycles. Importantly, this discipline also has <unk> positioned 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.
Alright, Thanks, Alan starting here on slide four 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 in our upstream joint ventures that base business increase was 6% over the prior year third quarter as we will discuss in a moment last year's third.
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 that 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 continued to perform very well, even as natural gas prices decreased 63% for the first nine months of <unk> 23 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 were generally flat with last year's strong cash flow and you'll see our third quarter dividend.
<unk> coverage based on <unk>.
<unk> was a very strong 226 times on a dividend that grew five 3%.
Our balance sheet continues to strengthen with debt to adjusted EBITDA now, reaching three four or five times versus last year's 368 times.
While 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 the.
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 six 7 billion in.
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%.
So even for the base business, excluding marketing in 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 base gathering rate at certain of our franchises in the west and northeast gathering and 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 in Gulf of Mexico business improved $83 million or.
Our 12%, including about a $47 million contribution from our mountain West pipeline and <unk> acquisition, 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 were higher margins tend to compensate for lower volumes and Thats, what we see in third quarter. This year with about a 22% increase in processing plant volumes led by those liquids rich systems.
With related increases in NGL production.
The volumes and associated fractionation and transportation revenues as well so shifting now to the west which decreased $22 million or 7% were 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 and.
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 at a lower working interest percentage on new wells beginning in January 2000.
'twenty three.
The warrants that are upstream EBITDA was down about $60 million.
Were 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 in 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 in Gulf of Mexico business improved $210 million or 10% really on similar themes as our third quarter, namely the impacts of the mountain west pipeline and <unk> acquisitions and still see.
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 that are dry gas areas and in the appendix, you'll find a slide that compares our 6% volume growth to the overall base and growth of just over 2%.
Shifting now to the west, which increased $20 million or 2% benefiting from a positive hedge results and strong haynesville volume growth, including the <unk> acquisition in the Haynesville, but the west was significantly unfavorable impacted by those lower natural gas price base gathering rates and also lower NGL margins.
And then you see the $122 million increase at our gas and NGL marketing business as Youll 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 wall.
Sutter 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.
Dramatically overcame weaker than expected results from the upstream joint ventures.
As I mentioned earlier, we are raising our adjusted EBITDA guidance to $6 6 billion to $6 8 billion with a $100 million shift upward in the mid point. This increase comes thanks to the steady performance of our base business, even after our 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 impact through April of this year and.
And this 2023 guidance raise kind of after two consecutive years of record breaking adjusted EBITDA growth in 2021 and 2022.
In the appendix Youll 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 will receive payment of the $602 million judgment awarded to us from energy transfer and the recent Delaware Supreme Court decision as well as the exact timing of the close date of the DJ or 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 everyday 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 365 times, even though that guidance was issued before consideration of the mountain west 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 the 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 out.
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're the most natural gas century 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, our 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 10 year track record.
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 worlds Energy Foundation with natural gas is going to happen, whether the opposition wanted to or not because we are running out of time and real world options to meet the growing need for energy, while reducing emissions nats.
Natural gas is the most effective non subsidized way of reducing emissions and it has become the practical alternative ramped.
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 dispatch will power capable of keeping up with the large number of government incentives 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 carb.
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.
Thank you Mr. Armstrong, ladies and gentlemen at this time do you have any question simply press star, one and we'd like to remind everyone that we do have the limit yourself to one question and one follow up question.
We'll go first this morning to Spiro <unk> at Citi.
Thanks, operator, good morning team.
Maybe to start with southeast supply enhancement, Alan you mentioned that being the largest EBIT contribution I think you said, we've ever seen which.
So roughly.
Maybe something we didn't depreciate. So curious if you maybe just provide a sense of how.
How are you thinking about the capital cost and 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 volume.
MBP comes online I know, it's something you've addressed in the past, but so it seems like some level of confusion there.
Yes. Thank you good morning, and thanks to Great question first.
First of all I wanted to clarify one thing because it might have gotten confused a little bit in the commentary.
The what.
When we talk about this potentially delivering another phase of expansion there the EBITDA that I'm talking about and the scale of the Abu Dhabi 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 is that that EBITDA that I mentioned being large.
Roger being the largest and being larger than our entire northwest pipeline system is on the initial one four Bcf a day for.
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.
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.
The physical capacities that we have out of there the total physical capacity out of there is five seven Bcf a day, two and half to the Newark to five to 700 million a day on the Virginia lateral so thats the existing capacity that we have out of their physical capacity that we have from $1 65.
Today, obviously, there's a lot of demand for that.
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 utilized and by the way utilizing our existing right of ways.
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 <unk>.
Terribly complicated project.
Easy for me to say that has responsibility for getting that done directly but but it is on our existing right of ways and.
And avoid a lot of the typical.
Eric wetland problems that we'd get into and tend to snag 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 could couldnt be prouder of the team and the way they work through this.
Got it helpful color and I appreciate the clarification on the EBIT contribution for that first phase.
Same question, maybe just turning to <unk>.
DJ Basin acquisition sounds like downstream benefits also.
Part of the decision to expand there so two questions on that front.
Does that seven X blended multiple impute any downstream benefits or is that sort of standalone for the assets and then two how.
How should we think about the curious on <unk>.
Volumes coming on to the downstream system is that something that happens immediately or do we need to wait for contracts to roll off.
I'm going to spare I'm going to have Chad zamin take that yes. Thanks Dara.
That seven times multiple really reflects the standalone.
Acquisition value and we do see significant opportunities to.
To integrate those assets it will take a little bit of time as there are some current commitments but.
<unk> has more volume that theyre gathering and they can process and deliver into downstream infrastructure and Rocky Mountain midstream had 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 that will roll off and that will allow us to move those volumes fully over to our system. So you will see that value.
Kris overtime.
Got it.
Thanks, Chad thanks, everybody.
Thank you.
Thank you the next now to Neil Mitra at Bank of America.
Hi, good morning, Thanks for taking my question.
First on a macro level it seems like some of the southern utilities.
Worried about having.
The gas supply, especially with a lot of the Haynesville moving north to south with projects like here.
There is a lag pipeline.
Are you seeing interest from from southeast customers.
Southern utilities too.
Haynesville gas on transco towards that area.
Yes, it's great question actually and I think the market will figure that out I think the way for instance, our lag project is structured.
That will give people the op opportunity as they come in they're Gillis 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 preferences and so that's the beauty of the Transco.
System as it gives people those options and the networking effect of our entire system that gives people greater market options set to appreciate so I'm not sure that people will have that a producer for for instance, we will have to declare one way or the other on that as much as they'll be positioned.
Enjoy the benefits of either one of those markets.
But we certainly are going to see.
I think competition for Haynesville supplies.
<unk> traditionally come in a lot of that has come in the station 85.
And that will certainly be in competition with $1 65 for a while and that will really dictate which way the volumes flow on there but.
But as those big LNG.
The LNG capacity growth is not all that hard to predict.
<unk>.
The projects are out there in the heart sneak up on anybody just because they are so big and takes so much longer so long for permitting so that LNG market is becoming very evident and it will certainly.
Takeaway supplies that a lot of the transco customers have dependent on coming in that station 85, and I do think to your point I do think that's why we're seeing such a such an interest in.
Picking up supplies off the mountain Valley pipeline, but I'll also tell you that's largely just because the markets are growing in.
In those areas is really what's driving that as they really start to run out of options for <unk>.
For meeting power generation loads in those areas.
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 our demand on the eastern.
<unk> in the United States continues to change there is there is 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 and then our footprints in the training services.
Great and then my follow up.
Texas to Louisiana Energy pathway project.
This is roughly $364 million.
In 2025.
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 meet transco volumes from from South, Texas, whether they're sourced from the Permian or Eagle Ford up to the Louisiana Energy corridor.
With compression or even looping and whether what are kind of the impediments towards.
Ailing up the size of transco to be able to do that.
Sure.
Hey, it's Michael Thanks for the question, Yes. The CLEC project is just a weighting of <unk>.
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.
Tell you we've got a lot of great opportunities to continue to expand that pathway on Transco, we have a lot of looping capability through that area additional compression that we can add and really move a significant amount of gas from south, Texas or the Katy area over to that Texas, Louisiana coastline worthy LNG facilities.
Or are being contemplated for expansion so really excited about those opportunities via our talking to parties on both sides of that whether it would 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 <unk>.
<unk> pipeline system.
To reverse is just north of Houston, there in that corridor.
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.
Got it and just to follow up on that answer.
The first class in terms of.
Approving a loop compression it's much easier.
I think that's what you did with with Texas to Louisiana pathway, but how much further would it be to get the regulatory filing for a loop on transco.
Once <unk> maxed out compression on that side.
Yes, so right now you know.
<unk>.
<unk> there their hurdle I would say for smaller projects like T lab. So it was originally an environmental assessment and FERC basically came back and said no we need any Ias and then they pivoted back and said no. This can go under an environmental assessment, which is a quicker process you probably save six to nine months.
On the environmental review typically between the eyes and in EMEA and I would say any looping project of any magnitude is most likely going to take an environmental impact statement.
And so thats.
Whether it be a looping or a greenfield.
It's going to be in the eyes and that process is typically one five to two years from filing two <unk>.
Approval. So I would just say that's the kind of the timeline you should be thinking about any type of looping project I would say the looping projects are less controversial when you start talking through the environmental organizations and.
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.
Sure.
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 a looping project because there's just less controversial at FERC is very interested in condemnation authority and the use of that these days.
And it gives us a great benefit when we're looking at looping projects just like our <unk> 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 expansions can do for our company.
Great. Thank you very much.
Thank you the next App to Theresa Chen Barclays.
Good morning, and thank you for taking my questions.
First on the DJ acquisition.
<unk> Standalone, how low do you think you can bring that in multiple with the downstream synergies and are there additional opportunities for portfolio optimization going forward.
Yeah. Thanks This is Chad.
Yes.
I want to speak specifically, but we are typically looking for leveraging our footprint and our strategic.
Positioning where we operate we have been focused on bolt on transactions that typically provide.
Better than one or two turns of synergies and optimization.
This is this is an integration that allows us to both increase gathering processing.
So we moved the Ngls down overland past week with our partnership with Targa, we can move the barrels all the way to Mt. Belvieu, where we have interest in fractionation and so theres a lot of opportunity to capture synergies along that value chain. So those are those are the kind of opportunity that we really look for that provide very clear.
Commercial and operational synergies.
That's really a focus as far as additional opportunities I think to 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 Corp, Dev and operating teams in finding opportunities to further take.
<unk> 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 in.
And again, taking that that kind of inefficient structure out of the business.
We'll continue to look for opportunities to do that and with scale.
And geographic footprint like ours.
These are these low risk high value bolt ons, I think will continue to be opportunities.
Got it and thus far into fourth quarter or.
Some color on progress made to date under marketing efforts just given the seasonal tailwind this winter.
Yes, I'd say, it's too early to really.
Speculate the winter is just getting started.
Got me the great thing about the sequent platform is it 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 and so we're well setup well positioned for.
The winter, if we see dislocations, but remember that.
That asset.
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.
Thank you.
We'll go next now to Jean Ann Salisbury of Bernstein.
Hi, good morning, and congrats on the southeast supply enhancement precedent agreements and I just had a couple of questions on that.
Does it start.
MBP goes in service and therefore kind of as a clock.
27.
It basically MVP starts a lot later than expected.
Matt.
No well just to be clear the agreements go the clock starts on those agreements with 20 years, when we placed the expansion in service.
And so that's that was referenced to 2047 I would say, it's pretty optimistic to think we would have that in service in 2027 certain would be probably the latter part of that.
<unk> standpoint.
Obviously.
We've set it up for permitting success. So we may be able to do that but 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 they are many of those agreements are dependent on mountain valley pipeline coming into service, but but not at that time.
Got it yes, I think I meant more for you to have the project online.
Valley gets pushed way your start date.
Also kind of get pushed because you might wait to.
To start working on it.
Oh, sorry, 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 2007 and it wouldn't be placed in service, but thats, what youre, 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.
Got it that makes sense.
Is it all going to be kind of the one four Bcf a day.
It kind of all one day kind of shows that not one day, but you know at one time or it could be sort of a phased in gradually leading up to.
And the final.
Right now our plans would be for it all come on at once.
Got it.
And then as a follow up.
Let people believed that we're entering a period of significantly more volatility in gas price and regional spreads in times of great can you guys just walk us through the specific part Williams portfolio that would benefit from this over time versus this year, which wasn't particularly volatile.
Obviously that also sort of market rate storage that gasoline gathering contracts that you referred to et cetera.
Yes, sure Chad you want to take.
And 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. 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 supplier has to be better connected to different markets, but ultimately volatility in basis differentials are what drive value across our core infrastructure and Thats why we think we're setup so well to continue to grow our base business and layer in just kind of the cherry on top layer in these these other.
<unk> 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.
Thanks, a lot.
Thank you.
Thanks.
Thank you the next now to Bryan Reynolds at UBS.
Hi, good morning, everyone.
Maybe to peek ahead to 2024, excluding todays acquisitions.
<unk> is around full year mountain west and some small expansions offset by some hedging headwinds. It seems like we're kind of just curious if you can maybe just talk about the existing base business and whether there are any rising tide as it relates to volumes or kind of what Jean Ann alluded to some nat gas storage opportunities are margin uplift that can move the needle one way or the other next year as we think about just 24 versus 20.
Thanks.
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, they're responsibly somewhat dependent on both the prompt price as well as.
The shape of the forward curve and so a little.
Little bit of TBD I would say in terms of volume growth on on the gathering systems and as that would affect.
Our gathering revenues I think on the transmission business.
Our opportunities there our acceleration of existing projects that we have out there. The team has been doing a great job like they did on RDA of bringing that first phase and early so I think the opportunities. There. If you look at our projects most of those come in including the big deepwater business come.
On towards the end very end of 24, 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 'twenty five.
So I think it's a little bit early right now frankly to be calling what we will see from the produce.
Producer community.
<unk> 24, and that will probably drive that on the margin, but I'll, let John take the more specifics.
Not a lot really to add I do think a really good reference for information about our growth in 2024 and really beyond as in slide 18 in the appendix.
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 of deepwater Gulf of Mexico business as well as several gathering and processing expansion.
You mentioned the full year amount was pipeline acquisition and now these DJ transactions that we're discussing today too that will that will layer into 'twenty four.
And you also mentioned Youre 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 Thats slide 18 in the appendix I think really clearly shows the projects that will be leading to the growth in 'twenty four 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.
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 to five years with some downstream expansion opportunities. So it's kind of just curious as 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, although 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 demand coming over the next decade.
Yes, Brian. Thank you were pretty careful to not put things.
And 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.
Don't have 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 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 would say that from.
A few fronts one.
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 when.
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 is pressure to take down other facilities up there and I just think thats.
People are going to have to get sober pretty quickly here on what the alternatives are up there I think our customers on <unk> are going to wind up looking really really smart, we're taking that capacity that they took because I think that's going to be impressions 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. 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 are well positioned to serve so it would be pretty shocking to me. If we didn't see that a lot of that backlog.
And the 25 and 26 really turned into some pretty material projects.
Great Super helpful. Hopefully some more returns like southeast supply I'll leave it there for the rest of the morning.
Thanks.
Thank you well go next vaccine Jeremy Toney at Infosys.
Okay.
And Jeremy Your line is open if you do have a question at this time.
Hearing no response, we'll move now to Tristan Richardson at Scotiabank.
Hey, good morning, guys.
Alan.
And you noted in your comments.
Prized at the level of demand Youre 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 this demand really but separate projects thinking way down the road.
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.
They are their demands are very urgent.
And for us to sit around and wait for to finalize any more of the demand that was <unk>.
Pending out there.
Really it doesn't serve those customers very well and so we're moving ahead with those customers that we are 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 timeline 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 with somebody else coming in under the wire before or we do our pre filing.
Yes.
But I would say.
We're not going to get ourselves.
<unk> 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 give 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 just like I said earlier I would be very surprised if we didn't see another project come out of this is just we're not we've got to get on with it because of the demands are similar.
That's great context, and then as we look out to 'twenty, four and 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.
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 <unk> just because we do have to make sure that we don't ignore any tax liability that.
<unk>.
Would start to affect that and so.
That's the reason for the switch from EBITDA to <unk> growth, but having said all of 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.
Here for the next several years at some point at some point.
Law of big numbers starts to overcome that but.
But for right now I think the 5% to 7% growth rate is very achievable within our dividend growth rate.
I appreciate it thanks al.
Thank you we'll go back next to Jeremy Tonet JP Morgan excuse me.
Hi can you hear me now.
Yes got you Jeremy.
Thank you good morning.
Just wanted to start off if I could with regard to capital allocation and just wondering.
<unk> talked about 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 right now price appreciation has decreased the yield a bit just wondering how this all mixed together.
Together with the higher rates today.
Yes, 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 our 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 are 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. So we will be revisiting our our ROE.
On our Transco rate base, and but again, we do have somewhat discretionary and <unk>.
Got 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.
<unk> 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 to buy shares as we've done in the past, 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 in a couple of reasons one given the structure of our gathering contracts and the inflation adjustment in those which goes against the entire race not against just the operating cost side of that right. 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 youre seeing the impact of high interest rates come across the alternatives as we think about power generation and infrastructure to meet.
Our generation demand.
In a simple term of 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.
As is very positive from a natural gas standpoint, just because of the capital required on the front end.
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.
Our industry in general as interest rates have moved up its just put more and more pressure on people's need to have natural gas.
As as a very real world alternative to meet the very rapidly growing power generation demand that we're seeing in the markets we serve.
Okay.
Got it makes sense I'll leave it there. Thank you.
Thank you <unk> for knee Scottish at Wells Fargo.
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 our utility customers have you observed any shift there in terms of their long term.
<unk> on natural gas and has there been any adjustments there in terms of their de carbonization timelines.
Yes, I think for a number of reasons I think even even some of the shifts we've seen here in the mid Atlantic States.
The rapidly growing demand that they're seeing from things like data centers and all kinds of incremental loads that they're seeing even 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 so yes, we're seeing that most mostly in the southeast and mid Atlantic States.
The northeast is yet to come I think people have kind of been holding out for that and I think theres 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.
<unk> very much the ourselves as a complement to renewables.
We are all for seeing that develop but here as we sit in the northeast answer your question we haven't seen.
The shift towards a 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.
They're seeing the demand growth in their markets and they've got to have an answer for it.
It's important to remember the fundamentals.
Eastern.
The United States, and there are less than 10% intermittent resources. Today. So there is they are just getting started and deploying alternative slides solar and wind and if you look at forecast for PJM.
I think widely understood that by 'twenty four. So this is long term by 2040 peak gas demand is going to double from where it is today. 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.
Got it and then switching gears on overland pass.
Do you see any disruption to volumes on the line. After one oak expands Elk Creek, if they decided 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 from the DJ assets could that potentially backfill any <unk>.
Loss on Oppo.
Yes. This is Mike will take that and thanks for the question, Yes, I would suspect if and when one okay.
Expansion, Doug would see less Bakken flows kind of maybe just because they've been diverting some of the flows into there'll be beall asset, we've got space and oppo today to bring in the DJ volumes, So thats really not a constraint.
As we see it today.
But certainly opening up more space is not a bad thing on oppo, ultimately, if we ever need to bring in more DJ volume, but we certainly enjoyed the.
Volumes from the Bakken.
One O because brought to our partnership.
Got it thank you.
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.
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.
Growth in the signs of even more growth that we're seeing in.
Across our strategy right now so.
Thanks for joining us and look forward to speaking with you next time.
Thank you Mr. Armstrong, ladies and gentlemen that does conclude the Williams third quarter earnings 2023 conference call again, we'd like to thank you all so much for joining us and wish you all a great day Goodbye.
Please wait the conference will begin shortly.
Yes.
Okay.
Thank you.
Yes.
Yes.
Okay.
[music].
Sure.
Sure.
<unk>.
Yes.
Okay.
Okay.
Yes.
Sure.
[music].
Yes.
[music].
No.
Sure.
Thanks.
[music].
Okay.
Yes.
[music].
Yes.
Yes.
Okay.
Yes.
Sure.