Williams Companies, Inc. (WMB) CEO Alan Armstrong on Q2 2021 Results - Earnings Call Transcript

Williams Companies, Inc. (NYSE:WMB) Q2 2021 Earnings Conference Call August 3, 2021 9:30 AM ET

Company Participants

Danilo Juvane - VP, IR

Alan Armstrong - President, CEO & Director

John Chandler - SVP & CFO

Micheal Dunn - EVP & COO

Chad Zamarin - SVP, Corporate Strategic Development

Conference Call Participants

Jeremy Tonet - JPMorgan Chase & Co.

Shneur Gershuni - UBS

Praneeth Satish - Wells Fargo Securities

Christine Cho - Barclays Bank

Tristan Richardson - Truist Securities

Spiro Dounis - Crédit Suisse

Michael Lapides - Goldman Sachs Group

Operator

Good day, everyone, and welcome to the Williams Second Quarter 2021 Earnings Conference Call. Today's conference is being recorded.

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. Please go ahead.

Danilo Juvane

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

In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in the presentation materials are non-GAAP measures that reconcile to generally accepted accounting principles, and these reconciliation schedules appear at the back of today's presentation materials.

So with that, I'll turn it over to Alan Armstrong.

Alan Armstrong

Good morning, and thanks, Danilo, and thank you all for joining us today. Our long-term strategy of connecting the fastest-growing natural gas markets with the best supplier continues to deliver solid financial results as demonstrated by our strong second quarter financials across our key metrics. Our stellar results this year were supported by equally strong fundamentals that demonstrate how sticking to this strategy has put us in an enviable position.

As evidence, Williams gas gathering volumes grew 6% in the first half of 2021, while the U.S.'s natural gas production volumes actually declined by 0.4%, continuing to prove that our assets are in the low-cost basins. We expect a constructive natural gas macro backdrop to continue to drive significant value for our business. Recent commitments to Transco market area expansions coupled with producer commentary on Transco projects such as our Leidy South and Regional Energy Access projects are clear pathways to growth for our Northeast gathering volumes for years to come.

We will walk through more details of our business in just a moment, but I want to first call attention to our 2020 sustainability report, which we just published last week. As this report details, we are making headway on critical ESG-related fronts. For example, becoming the first North American midstream company to set a near-term climate goal based on right here, right now emission reduction opportunities and making steady progress on developing our leaders for the future. We're also looking to the future as our nationwide infrastructure footprint is well suited and adaptable to renewable energy sources like clean hydrogen and RNG blending.

Williams' ongoing focus on sustainable operations positions us well to meet clean energy demand for generations to come. In fact, we are now up to 7 renewable natural gas sources flowing into our gas transportation systems, and we have 9 more that are in progress. I hope you can find some time to visit our website and read our new sustainability report. But right now, let me turn things over to John Chandler for a review of our 2Q and year-to-date results. John?

John Chandler

Thanks, Alan. At a very high-level summary, the quarter benefited from nice increases in profitability from our Northeast gathering systems, an uplift in revenues on our Transco pipeline from new projects that have been put into service over the last year and contributions from our upstream operations in the Wamsutter. These positives were offset somewhat by slightly higher operating expenses resulting from increased incentive compensation expenses, reflective of the strong performance that is unfolding this year.

And you can see the strong performance in our statistics on this page. In fact, once again, we saw improvements in our key financial metrics. First, our adjusted EBITDA for the quarter was up $77 million or 6%, and we have seen a 9% increase in EBITDA year-to-date. We will discuss EBITDA variances in more depth in a moment. Adjusted EPS for the quarter increased $0.02 a share or 8% and AFFO grew for the quarter similar to our growth in EBITDA.

AFFO is essentially cash from operations, including JV cash flows and excluding working capital fluctuations. If you put our year-to-date AFFO of $1.948 billion up against our capital investments year-to-date of $737 million and our dividends of $996 million, we have generated about $250 million of excess cash year-to-date. Included, as a side note, included in the capital investments is about $160 million of maintenance capital.

Also, you can see our dividend coverage based on AFFO divided by dividends is a healthy 1.96x year-to-date. This strong cash generation and strong EBITDA for the quarter, along with continued capital discipline, has led to our exceeding our leverage metric goal where we're currently set at 4.13x debt-to-EBITDA. You will see later in our guidance update in this deck that we've moved our guidance for the year from being around 4.2x by the end of the year to now less than 4.2x debt-to-EBITDA for the year.

So really strong performance for the quarter and the year, and the fundamentals are set up for a good second half of the year. So now let's dig a little deeper into our EBITDA results for the quarter. Again, Williams performed very well this quarter. Our upstream operations added $19 million of incremental EBITDA this quarter. And this EBITDA was entirely from our Wamsutter upstream acreage.

Remember that we owned the BP Wamsutter acreage the entire quarter, but only owned the Southland acreage for 1 month during the quarter. Production from the combined Wamsutter assets totaled 6.9 Bcf for the quarter. The Haynesville upstream acreage produced very little EBITDA, given it has only a small amount of PDP reserves. And therefore, it will take some time before we see new production and therefore, new EBITDA coming from these assets.

Now moving to our Transmission & Gulf of Mexico assets. They produced results that were $31 million more than the same period last year. New transmission pipeline projects added $25 million in incremental revenues versus the second quarter last year, including the Southeastern Trails project that went into service during the fourth quarter of last year, as well as a portion of the Leidy South project that also went into service in the fourth quarter of last year. And you can see this evidenced in the growth in our firm reserve capacity, which is up 5% from the second quarter of 2020.

In addition, our Gulf of Mexico revenues were up somewhat due to less shut-in issues compared to the second quarter of last year. In addition, commodity margins from processing volumes for processing the Gulf of Mexico gas was about $5 million due to higher NGL prices and higher volumes. These revenue increases were offset somewhat by a slight increase in operating expenses, again, mostly due to employee-related expenses, a large part of which can be attributed to higher incentive compensation accruals.

The Northeast G&P segment continues to come on strong, contributing $46 million of additional EBITDA this quarter. Collectively, total Northeast gathering volumes grew 750 Mcf a day or 9% this quarter versus the second quarter of last year, while processing volumes grew 33% and set a new record. The volume growth was predominantly at our JVs in the Bradford Supply Hub, where we benefited from a gathering system expansion on that system in late 2019; and at our Marcellus South supply basin, where we benefited from more productive wells of larger pads. And just to be clear, because we do not operate Blue Racer Midstream, those volumes are not included in our volume statistics. As a result of this volume growth, though, our EBITDA from our equity method investments improved by a little over $36 million, which also includes the benefit of additional profits that we do receive from Blue Racer Midstream due to the additional ownership we acquired in mid-November last year.

Now moving to the West G&P segment. It was down $21 million compared to the prior year. However, remember that first, we did agree to reduce gathering rates in the Haynesville in return for receiving upstream acreage in the South Mansfield area of the Haynesville. Again, as I mentioned, we are not yet seeing the benefit of those upstream assets but we have just named an operating partner to begin developing that acreage. The impact of the gathering rate reduction was about a negative $15 million for the quarter. In addition, in the quarter, we also saw $9 million less EBITDA due to a deficiency fee that One Oak paid us last year related to OPPL, which allowed them to pull volume that they had otherwise submitted to OPPL last year. One Oak does not have that volume obligation to OPPL this year, and therefore, we did not see the deficiency revenue this year. And finally, we did see a $9 million decline in deferred revenue from our Barnett Shale gathering assets, which is a noncash step-down in revenues.

So other than those 3 negatives, namely the lack of efficiency revenue on OPPL, the Haynesville rate decline and the deferred revenue step-down in the Barnett, our West assets were otherwise up $12 million versus the second quarter of last year. And this is in large part due to higher NGL margins, where once again, in our commodity marketing group is realizing more profit from elevated NGL prices. And while our overall gather volumes in the West were down about 3.5% versus the second quarter of last year, this was more than offset by better gathering rates, where in the Piceance and the Barnett, our contracted gathering rates are influenced by commodity prices.

So now moving to year-to-date results. Year-to-date, our results show growth of $230 million of EBITDA or roughly a 9% in EBITDA, driven, of course, by the impact of Winter Storm Uri in the first quarter and by many of the same positive factors that I just mentioned affecting second quarter growth. Combined between our marketing activities and our upstream operations in the Wamsutter, winter storm Uri had a combined positive impact of $77 million. In addition, our upstream operations otherwise have added an additional $27 million year-to-date.

Our Transmission & Gulf of Mexico assets are up $22 million year-to-date or about 2% better, with this increase being driven largely by additional transmission revenues from new projects that have been put into service and incremental revenues from Gulf of Mexico assets, largely due to lower downtime this year versus last year. These positives were partially offset by lower revenues from 1 less billing day on a regulated transmission pipeline and higher expenses, where, last year, expenses were delayed due -- some due to COVID and because this year's expenses, again, are higher due to higher incentive compensation expenses resulting from our strong performance.

Our North G&P assets are up $78 million, almost entirely driven by profits from our JV investments, namely from the Bradford Supply Hub gathering system and our Marcellus South gathering systems. In addition, we benefited from the increased ownership of Blue Racer Midstream. In total, gathering volumes for the Northeast are up 10% versus 2020, while processing volumes year-to-date are up 24%.

And then finally, the West, West E&P is up $23 million versus the year-to-date last year, and this is on top of the $55 million that we earned from winter storm Uri. The $23 million increase is driven by higher commodity margins and slightly lower operating costs, offset by lower Barnett deferred revenues, lower Haynesville gathering rates, which were exchanged for upstream acreage, and lower OPPL deficiency revenues that I just mentioned in my 2Q remarks. Otherwise, we did see a 5% gathering volume decline year-to-date, but that again was more than offset by MVCs and higher gathering rates, as again, I mentioned in my second quarter remarks. Again, this is stacking up to be a very good year for us.

I'll now turn the call back over to Alan to cover a number of key investor focus areas. Alan?

Alan Armstrong

Great. Well, thanks, John, and we're moving on here to the key investor focus areas here on Slide 4. First of all, regarding our financial expectations, we are on track to generate EBITDA closer to the high end of our guidance range that we just increased at the last earnings call. The resilience of our business has supported our financial results and helped us recently overachieve against our previous leverage metric goal of 4.2x. As a result, we recently received a Moody's upgrade to Baa2 and now have a BBB equivalent credit rating amongst the 3 key rating agencies.

Our free cash flow outlook for 2021 remains intact. And in fact, the long-range plan unveiled during our most recent Board strategy session forecasted continued steady growth in EBITDA and continued improvement in our credit metrics. Importantly, our long-range plan also shows that even after funding these many growth opportunities, our business is poised to generate significant excess free cash flows that will support a robust and multifaceted capital allocation approach that will enhance returns for our shareholders, including the potential for opportunistic share buybacks, so stay tuned on this front.

Next, looking at our recent transactions and project development. Our -- first of all, the upstream JVs, great effort on the organization here. As we announced last month, we were able to finalize an upstream joint venture with Crowheart in the Wamsutter basin, consolidating our legacy BP Southland and Crowheart upstream assets into 1 contiguous footprint of more than 1.2 million acres. So as we've mentioned before, this acreage was very divided and checker-boarded out here. And so being able to consolidate these assets in a way that it can be developed at a low cost is really critical to the value of the upstream business, important to us to the midstream business and taking advantage of the latent capacity we have out there today.

And just recently, we inked a joint venture with GeoSouthern in the Haynesville that provides us with the following benefits: first, it unlocks significant midstream value for Williams through GeoSouthern's obligation to develop the South Mansfield acreage. Under this agreement, GeoSouthern will carry a portion of our drilling cost and will earn increased ownership in the leaseholds as they deliver on agreed-to development milestones. Second, it provides Williams with the opportunity to optimize all of the natural gas production in the area through fixed fee agreements marketed by our Sequent business. And third, with the South Mansfield being in close -- with South Mansfield being in close proximity to Transco, it provides Williams with future development opportunities, including the ability to source and deliver responsibly-sourced natural gas into the growing LNG market.

Importantly, both of these recent JVs improve the value proposition in the Wamsutter and the Haynesville basins as we're partnering with well-positioned, high-performing local operators and the deals require development of the properties driving volumes to our midstream and downstream assets. From a project execution standpoint, we continue to deliver on multiple fronts, including bringing online key projects such as Leidy South, which is on track for an early in-service now before the winter heating season.

And importantly, Transco growth opportunities remain highly visible, and we've recently received customer commitments for 2 new market expansion projects in the Mid-Atlantic region. Transco also has ample runway to provide additional low-risk growth through rate-based modernization projects. In the deepwater Gulf of Mexico, we continue to highlight the great growth it continues to show for us out here, and we've recently reached definitive agreements for both the Shenandoah and the Whale projects, these will contribute to significant EBITDA growth beginning in 2024.

And then finally, on sustainability. I mentioned our sustainability report at the top of the call, and we also filed our carbon emissions disclosure with the Carbon Disclosure Project last week. I'll just add that we continue to leverage our natural gas-focused strategy in today's technology to deliver on immediate opportunities to reduce emissions. At the same time, natural gas and our infrastructure are enabling the next generation of clean energy technologies.

The next wave of renewable power generation will be up against 2 key constraints: both the transmission and the storage of energy. No other energy infrastructure system integrates a reliable delivery network into critical population centers with a massive storage solution on the scale that natural gas transmission does. We believe our infrastructure can be a critical part of both near- and long-term solutions.

We continue to advance our solar projects that were announced last year, and I'm pleased to share that we have 6 projects now awaiting approval from the grid operator with another 10 ready for the same regulatory approval by the end of 2021. In total, these 16 projects amount to about $250 million in CapEx. It should start to cash flows beginning in 2023, and we have another approximately $150 million of these similar projects that are under development. We are looking forward and anticipating future innovations and technologies that we can use on our key energy networks to deliver on our country's clean energy future.

And in fact, in a partnership with the University of Wyoming, we recently awarded a $1 million -- we were recently awarded a $1 million grant from the State of Wyoming to fund a feasibility study that would evaluate the creation of a green hydrogen hub near our operations in Wyoming. And this really is another example of how we continue to leverage our existing assets and footprint to drive clean energy solutions. In the Wamsutter, we now have 1.2 million acres dedicated to our midstream assets through the Crowheart JV. But in addition to that, we have about 200,000 acres where we own or control the surface rights, which we intend to leverage for clean energy development.

So in closing, I'll reiterate that our intense focus on our natural gas-based strategy has built a business that is steady and predictable, with continued growth, improving returns and significant free cash flows. This has translated into a strong balance sheet and a well-covered and growing dividend. Our best-in-class long-haul pipelines, Transco, Northwest Pipeline and Gulfstream, are in the right place and the right markets. And by design, our formidable gathering assets are in the low-cost basins that will be called on to meet gas demand as it continues to grow.

We remain bullish on natural gas because we've recognized the critical role it plays and will continue to play in both our countries and the world's pursuit of a clean energy future. Natural gas is an important component of today's fuel mix and should be prioritized as one of the most important tools to aggressively displace more carbon-intensive fuels around the world. Our networks are critical to serving both domestic and global energy demand in a lower carbon and economically-viable manner. And with that, I'll open it up for your questions.

Question-and-Answer Session

Operator

[Operator Instructions]. Your first question comes from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet

I was just wondering if you could start off a bit expanding on your thoughts on the current gas macro outlook, and whether that backdrop drives the higher end of guide expectation. How does this position your trajectory into 2022 at this point?

Alan Armstrong

Yes. Sure. Jeremy, as you know, the pricing run-up that we've had more recently and the continued demand growth is really starting to obviously put pressure and kind of wake up the forward markets a bit. And certainly, we are seeing responses from our producers looking to take advantage of that. The area that, I would say, that will see kind of the quickest response to is probably the Haynesville and tremendous amount of drilling activity that's gearing up in the Haynesville right now.

But as well, you heard -- probably follow the comments from Cabot on their earnings call. Strong response there to price there as well. And of course, in the Southwest, Marcellus and in the Utica as well, we're really seeing pretty strong response across all those areas. So I think it's important to note that this is not just a production issue. Demand continues to grow. And so if you're looking at 2Q comparisons, we've seen against the '19 2Q, we saw demand grow by 9%. And against a 2Q of '20, we saw it grow about 5.6 -- sorry, yes, about 5.6%. So continued really strong growth going on, on the demand front. And we're obviously seeing prices respond to that.

But I think, from our perspective, as we said all along, it really is demand that is going to drive our business and price will fluctuate as required to balance that, but it really is this demand -- continued steady demand growth that we're continuing to see. And obviously, as we saw last year, we don't expect the COVID or a resurgence of COVID really to have any impact on that. We're continuing to see a steady, healthy growth coming on the natural gas market. So as we look into '22, kind of hard to predict what gas demand will continue to do. But right now, certainly, the fundamentals are looking strong, and we are seeing a healthy producer response.

Jeremy Tonet

Got it. That's helpful. And I realize I'm probably getting a little bit ahead of myself here, but as it relates to buybacks, just wondering whether Williams has authorized a buyback plan. And if not, what would it take to authorize it?

And as you think about -- if you were going to pursue buybacks, would something just generally opportunistic in nature make the most sense? Or something systematic where a percentage of cash flow could be applied to that in a given year? Just wondering, at this stage, what your thoughts are on buybacks in those respects?

Alan Armstrong

Yes, Jeremy, thank you. I might as well get this out of the way. I knew that question was coming. So I'll square up on this. So first of all, we did have a really important discussion with the Board last week. And I think probably what was most remarkable about that was the degree of free cash flows that continue to exist on top of funding growth capital, on top of continued deleveraging that comes with that growth in EBITDA and being able to fund both rate base investments and new energy venture investments. Allowing for all of that, we still are showing pretty significant excess amount of free cash flow. And so I think that's probably the biggest takeaway.

In terms of a program, we are in the process of detailing that out with our Board and putting some specific parameters around that. But I can tell you that the recommendation will be that it will be somewhat opportunistic, but it will have some framework to it in terms of what appropriate pricing levels and what those drivers will be. And I can tell you from my perspective, that will likely be a multiple of wherever our debt is trading. And if you think about that, our debt has continued to stay very steady while stock price has flipped around. And certainly, there will be those times where the market runs into its scares like we saw in March and April of last year. But in reality, the debt markets have been very steady and yet prices whipped around quite a bit.

And so we think that will point to when the right opportunities are to acquire stock. So it will have parameters around it. It won't just be perfect -- it won't be random, and will have parameters around it in both in terms of size and the drivers for that. We likely won't announce those specific multiples on the debt multiples, but that is how we're thinking about it right now. And we will be announcing -- we do intend to, I should say, announce the program once we get the details of that squared away with our Board.

John Chandler

And Jeremy, probably I'm self-evident here, but what Alan is really referring to is our dividend yield in relative comparison to where our debt trades at.

Alan Armstrong

Thank you, John.

Operator

Your next question comes from the line of Shneur Gershuni with UBS.

Shneur Gershuni

Maybe just to follow up on Jeremy's question there a little bit. Alan, in your prepared remarks, you had put a comment out there about how your projections to the Board showed steadily increasing EBITDA and steadily declining leverage. Should we think about this as there's a new leverage target that needs to be achieved? Or should we think about it as this excess cash flow is going to -- a component of it is going to go towards leverage reductions that will continue to decline? And then a portion will be available for the buybacks, whether it's 50-50 or to be opportunistic. Is that the way we should be thinking about this? I'm trying to square those comments together.

Alan Armstrong

Yes. Well, I think the easiest way to think about it, Shneur, is that we, with our EBITDA continuing to grow and we hold our debt where it is, obviously, that metric continues to improve. And so really should think about it in that fashion. And so that's the primary driver of that improved credit metric.

And I would just say that we will be able to balance that and make decisions on that as we see fit through the process. But there is such a significant amount of excess cash flow coming off that we really feel like we can hit all of those things we'd like to in terms of both continued dividend growth, continued credit metric improvement investment in our rate base and driving earnings assessment in our rate base and new energy ventures.

We can do all of that, and we still have pretty significant firepower left for share buybacks when the opportunity is right. So really, the message we -- folks ought to be getting is that the cash flow is very significant, and it allows us to invest in all of those measures to continue to drive shareholder value.

Shneur Gershuni

I appreciate the clarification there. Maybe to pivot a little bit. I was recently reading your sustainability report and you're talking about evaluating hydrogen and you sort of talked about that a little bit here. I'm just wondering where you see Williams' role in the hydrogen value chain. Because you talked about both blue and green in the comments there. Do you sort of see Williams as really just in the transportation aspect of it? And is that where you expect to invest? Will it be on the reformation side? Or do you actually see yourself participating capital-wise on electrolysis?

I'm just trying to get a sense of how you're thinking about it because as I sort of think about your position in the Haynesville, it kind of seems like a blue hydrogen strategy would be very interesting where you could participate in creation and in the transportation to industrial centers in the Gulf Coast. So just kind of curious of where you feel Williams will be, let's say, in 3 to 5 years from now on the hydrogen strategy.

Alan Armstrong

Yes. I would just say, and I'll let Chad Zamarin follow up with some comments here, if he likes. But I would just start and say that what will be most obvious to you is that we're going to invest where we have competitive advantages around our assets. And so obviously, that points to transportation. But we do believe that in places like Wyoming where we've got such big land mass available and we have the transportation, and we have the processing capabilities and the system is already set up. We don't think that's a stretch for us to at least study.

So a couple of things. One, it is going to -- we're only going to be doing it where we're making decent returns. And that means that we're going to have to be using competitive advantages to get returns that are over and above kind of what the market is allowing today on that kind of investment. And then secondly, you should think about it in terms of us always making sure that we are not leaving an opportunity where we have a competitive advantage.

We're not going to let one pass us by, so we're not letting any -- we're not going to be taking any strikes at the plate and making sure that as we see opportunities, that we're attacking those very quickly. So Chad, I don't know if there's anything you might add to that.

Chad Zamarin

Yes. I think you said it in your remarks, we operate an incredible energy transmission and storage infrastructure, and we're very focused on ensuring that, that infrastructure is part of the solution for the next generation of energy. And so that's our primary focus. I would say it's early in the days of hydrogen and we are working with the hydrogen production side of the equation to ensure that it can be economic and that it can drive volumes to our infrastructure.

So I think we will participate in a small way initially to ensure that, that technology develops in a way that complements our infrastructure and then we'll evaluate whether or not we would invest on an ongoing basis. We're working on -- you mentioned the Haynesville. We permitted our Regional Energy Access project in a way that we've defined as compatible with hydrogen blending. And we're working on a hydrogen project, a pilot project on our Regional Energy Access project that will involve us participating in the production of hydrogen. It will be a very small scale, but it will demonstrate that we can leverage our infrastructure and we will earn an attractive return on that kind of investment.

We're looking at that across our entire footprint. And as that scales up, I think it will be exactly what Alan said. It will be, "Do our strategic capabilities and assets provide us with an advantage? And should we leverage that advantage into investing in hydrogen production? Or just be prepared to support that development and drive those volumes to our assets and infrastructure?" But I can tell you, we're looking at it and read the table across our footprint to make sure that we're driving forward the right solutions to support our business.

Operator

You have a question from the line of Praneeth Satish with Wells Fargo.

Praneeth Satish

So now that you've executed on the Wamsutter and Haynesville JVs, I was just wondering if you could help provide some clarity into the incremental midstream EBITDA you could pick up in '22 and '23 versus the upstream cash flow that's lost. Just -- I guess I'm just trying to figure out how accretive these transactions will be.

Alan Armstrong

Yes. I would start off with they are surprisingly powerful anytime you start adding volumes to late -- to mostly latent capacity in an area that it obviously comes on fast. So there's not any midstream permitting facilities are sitting there ready to go. So it is very powerful, and that's why we've been so focused on this. So I think we're all very excited about that. I'll let Chad speak to kind of the metrics on what we look like for growth in those areas on the...

Chad Zamarin

Sure. And I'll give a little more color on the Haynesville structure that I think will help folks derive how much value that's going to contribute. But with GeoSouthern, we're thrilled to announce that partnership, they're a well-proven operator with a long track record of development. And with GeoSouthern, there is a drilling commitment of over 400,000 lateral feet that they will be pursuing. And you think about our acreage, it's highly contiguous and you see a map, there's a map in our appendix that shows how it's complementary with GeoSouthern's footprint.

So there's a lot of long lateral inventory at very economic returns. And so we expect them -- they're incentivized. There are penalties if they don't meet those drilling commitments, but beyond that, we expect them to outperform the drilling commitment because it's highly economic opportunities. And as they perform, the initial economic splits have GeoSouthern at 30% of the economics, Williams at 70% of the upstream economics, but they will carry us, our capital for upstream development up to a cap of $50 million. And once that cap is achieved, they will revert to having 75% of the upstream economics and Williams will have 25% of the upstream economics. So they're highly incentivized to continue that development.

To give you an idea of how powerful that is for our midstream systems, that development, we would expect to drive somewhere around 400,000 to 500,000 dekatherms a day of volume to our midstream assets. That's incremental volume from what we have today. And that ramp occurs relatively fast over the next 18 to 24 months. And all of that gas is committed to our midstream systems at a fee of $0.32 for gathering and treating. And as Alan mentioned, that is primarily available capacity that will be extremely high margin for us. And on top of that, we then have the ability to market that gas and drive that gas towards downstream opportunities, including integration with Transco.

We've talked about marketing through our newly acquired Sequent platform. We're going to be working on a wellhead-to-water responsibly-sourced gas solution that we can offer to customers. And so just the base business alone, there's a lot of value to be driven to our midstream assets in that area. And if you do the math, it will rapidly outpace what we gave up from a fee reduction perspective with Chesapeake. And so that gives you kind of a picture of the Haynesville. In the Wamsutter, similar structure a little bit and it's a very big asset that we were working on.

And again, thrilled with Crowheart as our partner. They have been in the basin for several years. If you look at the map in our appendix, you can really see the industrial logic, again, of partnering with Crowheart. And we put together over 1 million acres of now-contiguous acreage. And with Crowheart, there is a drilling commitment of over 500,000 lateral feet. And as we have announced, there's a 75-25% initial split with Crowheart at 75% and Williams at 25%. But as they achieve performance across that 500,000 lateral feet of development, they have the ability to earn up to a 50-50 split. And so they're highly incentivized to drive volume growth.

And in the Wamsutter basin, again, we have latent capacity that's very high margin gathering and processing. It's dedicated to us. We gather and process for approximately $0.60 a dekatherm, so very high margin business in that basin. And we have today around 300 million cubic feet a day of volumes. That system has over 700 million cubic feet a day of capacity. So on top of the gas gathering and processing, we are now -- we've dedicated all of the NGLs at Williams at a fixed margin to Mont Belvieu pricing. And so we don't wear commodity price risk, and we cover significant revenues for Overland Pass Pipeline for Bluestem and our downstream partnership with Targa. So that hopefully gives a little bit of color on how those will drive value to our midstream and downstream assets.

John Chandler

But maybe just to give you a couple of numbers here real quick because the Haynesville is different to the Wamsutter. The Wamsutter has very significant PDPs today, and where the Haynesville acreage doesn't. So we'll need to be drilling that up to produce the midstream value and the upstream value. And that will really start coming on in '22 and really into '23.

That Wamsutter, on the other hand, with gas prices being quite a bit higher, is significantly paying for itself. And I'm not going to give you exact numbers here, but I can tell you what we paid for the South for the acreage from Southland and for BP will be completely paid for in less than 2 years and with where we see gas prices and just PDP production. And of course, that development will occur and you're going to see meaningful EBITDA uplifts coming in the future beyond 2022 as those new wells are drilled and that production comes on.

So in the Wamsutter, you can get a sense of the return there just simply because of the PDP production and the gas prices. We'll return our capital very significantly in a very short time frame. In the Haynesville, as we look at total NPV value, yes, we did give up rates with Chesapeake in the Northern part of our system. They're bringing more rigs to work in that part of the system, but the value of that acreage as it's developed and we look at that -- I won't give you the exact number, but when we look at NPV, the value generation is at least $300 million, actually higher than that, over the life of this. That's the combination of the upstream value and the midstream value uplift from this, from the South Mansfield acreage.

Alan Armstrong

Yes, I think that's well put, John. It's, I think, also a great example of creating a win-win for us and our customer. Chesapeake has been able to increase activity. And we, this time last year, Chesapeake was still not running rigs in the Haynesville. With the fee reduction that we offered, they now have 3 rigs running in their Springridge area. And so the fee reduction has incentivized significant activity that will show up on its own as incremental earnings over time. But also, as John mentioned, through the South Mansfield transaction, we see that as virtually tripling the value of that give back from an NPV perspective. So really, with Chesapeake made the pie much larger, and we're both able to benefit from that transaction.

Praneeth Satish

Great. Super helpful. Just kind of switching gears for a second. I was wondering if you could comment broadly on the RNG business. I know in the past, you've been a little reluctant to invest in the actual RNG facilities. But now some of your peers are moving more aggressively into the space. So I'm just curious whether your views or strategy on RNG have changed at all.

Chad Zamarin

Yes, this is Chad again. I think we've said that we are willing to invest in RNG aggregation and processing if it makes sense from an economic perspective. And again, similar to what we talked about hydrogen, we have a strategic advantage. We have been looking at our footprint. We've been identifying sites that have potentially attractive economics from an RNG capture processing and delivery perspective. We think that, that opportunity set is attractive economically, but relatively small in scale. We've talked about a couple of hundred million dollars of potential investment. We have a few projects that we are evaluating where we could invest in the actual aggregation and processing of those volumes.

The project that we've done so far have primarily been just interconnects into our existing infrastructure. But the technology required for those investments is relatively straightforward. I will say it's one of the areas that we look at that is heavily dependent upon LCFS credits and RINs. And that is an area where, again, we're going to be disciplined in our investments. We're not going to develop our entire business strategy around areas that require heavily subsidized economics.

And so I think there's a place for it where we can drive significant value because of our strategic footprint. And I think we can invest at a level of modest and will -- and I would tell you because of those LCFS credits and dependency on those credits, we're identifying those opportunities in areas where we would have pretty rapid payback of those investments. So very attractive returns that would provide us with the confidence in those structures.

Alan Armstrong

Yes. I would just chime in on and supplement the comment on the subsidies there, and certainly, the LCFS, the low carbon fuel standard, and the RINs are really the big driver in those projects. And if you start looking at the weight on the LCFS program to California, in particular, I think that's something we certainly are going to be paying attention to is the degree of sustainability of some of these credits and subsidies that are out there and making sure that we're not overinvesting against that risk.

So it's not to say that we won't find ways to monetize that on the front end or let somebody else take that risk, but I do think that's a risk worth keeping your eye on given the -- if you add up all of the various projects where there's a CO2 carbon capture on ethanol load that that's putting on there and the loaded R&D starts to put them on there. It starts to be a pretty big number. So I think that's an important thing to keep your eye on as an investment.

Operator

Your next question comes from the line of Christine Cho with Barclays.

Christine Cho

Maybe if I could just get a clarification on the leverage. What is the long-term ownership percentages for both Haynesville and the Wamsutter? What sort of timelines are we thinking about? And how should we think about how the upstream contributions are factored into the leverage calculation? Is 4.2x still the right target? And is there any change to how the rating agencies view that?

Alan Armstrong

I don't think there's any change. I would just tell you, Christine, that the metrics are coming down again pretty naturally. And the cash flows start to roll from the upstream to the midstream pretty rapidly over the next 3 years. And so it does take a little bit longer in the Wamsutter. The development in Haynesville is pretty quick. So it rolls over to that pretty quickly. And certainly, the rating agencies are well aware of our strategies and design on how we get there. So John, I don't know if you got anything to add.

John Chandler

No, I think that's right. Again, the Haynesville, both deals are designed -- both structures in the Haynesville and Wamsutter are designed for us to reduce our interest. And as Alan said, the Wamsutter sets us more sizable position, our interest would be bigger for longer there. And so whether that ultimately transfers to our partner or gets bought out in those, we don't have a long-term intent to be in the upstream business and intend just to do this to drive value in the midstream. So not sure exactly how Wamsutter ultimately plays out over long term and the Haynesville is pretty clear that as long as the drilling curves like we expect, as Alan said, in a 2- or 3-year time frame, it converts over to midstream value.

In the meantime, our credit metrics are so strong right now and our coverage of our dividend and coverage of cash flows. We've talked to rating agencies about this, and I don't sense a concern at all about it. But again, as Alan pointed out in his opening comments, we do see growth coming in our business from EBITDA, which creates natural deleveraging and allows us to do a lot of incremental things in addition to what we're doing today and still see those metrics improve. And so the rating agency has seen numbers that show that as well.

Alan Armstrong

It is a good question. I think to really understand how that transitions, if you look at the cash margin that we make on the midstream side versus the cash margin on the E&P side, you can see that there's so much value driven to the cash flows on the midstream side. But that's really what makes this work and kind of transition us -- transitions us out of the upstream piece of it and into the midstream cash flows pretty quick. So as we've said all along, our goal is to get those developed rapidly and get the cash flows moving on that.

In the Haynesville, that's a shorter-term issue and on Wamsutter, that's a longer-term issue just because it's such an enormous deal that will -- is going to be providing -- has such a tremendous amount of inventory in that area, so -- but it really is the cash margin of the midstream business that is really powerful for us. Our cost side of that doesn't move very much at all on the midstream side, but cash flows go up pretty dramatically.

Christine Cho

Okay. Got it. And then if I could just move over to the Northeast. Your processing volumes jumped quite a bit there quarter-over-quarter. Do you guys benefit from some short-term volumes with a competitor outage? Or is that a new run rate we should go off of?

Micheal Dunn

No, Christine. This is Micheal. That -- those outages that occurred, they were very short lived. And ironically, we were -- both the big operators up there were having some operator challenges at the same time that were quickly resolved. So we didn't really benefit nor did our competitors at that same time.

But I would say if it is a new run rate for us just because our Oak Grove TXP III project came online in the first quarter. And obviously, we have filled that up in the second quarter and are running at full tilt there on our OVM processing for the most part. And so we are looking at opportunities to interconnect with our Blue Racer facilities and take advantage of some potential lease capacity that they may have. But there's an opportunity to round robin a lot of gas there to our own facilities, our UEO that we acquired a couple of years ago as well as the Blue Racer facility now that we are going to take full advantage of.

But I would say we're seeing very active producer activity up there from EQT and Southwestern as well as Encino, who's a private operator, and they are chasing those liquid-rich well pad drill outs right now, and that's why we're seeing a lot of activity there and really pleased that our processing capacity is not full.

Operator

Your next question comes from the line of Tristan Richardson with Truist Securities.

Tristan Richardson

I really appreciate all the comments around your level of capital allocation. But just thinking about the cash flow build next year against some of the project opportunities you've talked about, particularly rate-based investment, the new energy projects awaiting approval, Gulf of Mexico FIDs. Should we think CapEx in 2022 could look similar to this year as some of these opportunities kick off and dollars start to be put to work?

Alan Armstrong

Simple answer is yes. One of the things that's driving capital expense this year has been some of the upstream acquisitions as well as the Sequent acquisition. And so we've had some acquisitions that have -- are still included in that range that we've put out, so that's driving this. Next year, Leidy South will be completed. In the fourth quarter of this year, most of the capital spending obviously will occur prior to that.

And then as we get into next year, hopefully, we'll start spending towards the end of the year on Regional Energy Access. If we're fortunate on the permitting process, most of that spending will be in '23. But in addition to that, as we get into '23, the spending for Whale will hit as well. So it's looking pretty levelized, frankly, with this year being driven a little bit higher than we would have expected with some of the acquisitions that we've done. But next year, continued expansion in a lot of these projects that we've mentioned. So it's -- looks like a pretty relatively steady run at kind of the current rate and capital spending.

John Chandler

I'd just say that the math is obviously pretty straightforward. If you look at our -- if you just use our guidance midpoint as a starting point, other than capital, we'll be at the higher end of the range on capital. We're generating -- we're spending, let's say, $1.2 billion at the high end on expansion capital, $500 million on maintenance this year, so that's $1.7 million still deleveraging.

Next year, we see EBITDA growth. We're not giving explicit guidance on that today. But if you think about it, if we just put a 4x multiple against any EBITDA growth, that still allow us to be leveraging from a 4.13 level today. And so any kind of reasonable amount of EBITDA growth adds substantially on top of that $1.7 billion that we're spending this year. So that's what -- you hear this kind of confidence on our part that we've got -- we see EBITDA growth coming and with that comes an obviously an expansion of that investable capital and still allowing for a deleverage from a ratio standpoint.

Tristan Richardson

I appreciate it, John. That's helpful. And then I guess just a quick follow-up on really on the acquisition opportunity side. You guys have talked about capital allocation across CapEx and the balance sheet and even the potential for repurchase. Curious on asset packages out there. We've seen some activity in transmission and storage over the past year. Are there small bolt-on opportunities out there, either in the Northeast or in the West? Are there things that are attractive or even transactable when you look out across the landscape?

Alan Armstrong

I would say we certainly keep our eyes on that. And so far, I think folks that are more dependent on those acquisitions for growth are making those acquisitions. And so from our vantage point, we've got better investment opportunities right now than that. And hopefully, that will continue for a long period of time. It's certainly looking that way right now. But I think that's kind of what's driving that market right now is whether people have growth or not. And for us, we have very substantial growth within our investments that are better return opportunities than what we've seen in the broader M&A market -- at option M&A market produced right now.

So we'll certainly keep our eyes open, and -- but it's going to be deals that where we have a tremendous amount of synergies that can make those investment opportunities compete with our other investment opportunities, including share buybacks as well. So all of those go into that calculus. But right as we've demonstrated, we're going to be very patient. And we're going to do deals that are -- where we're competitively advantaged to get a much higher return than the broad market would be able to realize.

Operator

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

Spiro Dounis

Alan, first one for you. In the past, you've expressed interest and a willingness to work with the current administration on energy transition and emissions goals. Curious what receptivity you've had early on in demonstrating natural gas' role in the transition. And what you see is maybe still some of the hurdles or areas where there's a gap of opinion on how you approach reducing emissions over the long term.

Alan Armstrong

Yes. I think it's an interesting time right now because there is this big drive to -- everybody is very focused on emissions reduction. There's starting to be a sobering, if you will, and a realization of what that means from a cost standpoint to consumers. And as a result of that, people are kind of pivoting back to, okay, well, what is sensible and what can we do that makes sense. And enter the likes of Senator Manchin with a great focus on natural gas for the benefit of the state of West Virginia and for our country and jobs, I would say, and a strong recognition on his part that we have to do this in a globally sustainable manner. And it has to be economic. Otherwise, we're just shipping jobs and the industry off to other countries.

And so I would just say there's kind of a reconciling going on, if you will, between, and no pun intended there, by the way, between the intense focus on carbon reductions and tackling that issue on the one hand and on the other issue doing it in a way that it actually is sustainable and we, as the U.S., can stay in control of our own destiny from an economic perspective. And so I think natural gas is extremely well positioned as those 2 things start to grind against each other and start to look for sensible intelligent solutions that we can really deliver on today.

And so I would say I have seen some recognition start to go on as people start to actually think about what the cost of some of these solutions means both in terms of direct cost of consumer and in terms of reliability. And so the issues are starting to sober up a little bit as people really start to describe solutions. And so I think where -- natural gas is even better positioned right now than I kind of thought it would be because I am noticing that people are starting to pay attention to the impact on consumers.

Spiro Dounis

Understood. Helpful. Second question is just a follow-up on Sequent. I know you've talked about EBITDA generation in sort of the $20 million to $30 million range annually. But I don't imagine that contemplates the uplift Sequent could provide to the entire asset network as a whole. So curious, am I right in that assumption? And is there any way you can sort of help us quantify the potential benefit overall as Sequent starts to ramp up and integrate into the system?

Alan Armstrong

Yes. Unfortunately, I don't think we're going to be able to provide you any specific numbers on that. But you are correct. That is really the purpose of that acquisition, was to drive further value and benefit. And I would tell you, so far, we are even more excited than when we were looking at the acquisition originally in terms of synergies between what our Williams existing customers want and we can provide services for, and what Sequent has and that team has to offer. So tremendous synergies, really excited to see the team starting to work together, and they're identifying a lot of opportunities here very rapidly. So the honeymoon continues, I guess, I would say, and we continue to be very excited about what we're seeing from the Sequent team and their ability to drive value across our asset base.

Operator

Your last question comes from the line of Michael Lapides with Goldman Sachs.

Michael Lapides

Two-parter here. One, can you remind us what's the capital investment required for the deepwater projects for the 2 that you're kind of disclosing? What should come online by 2024? That's the first question. Second question is, what's the next step in terms of approval process for Regional Energy Access?

Alan Armstrong

Yes. I'll take the first part of that on the capital. We haven't disclosed specifics on that capital, but I would just tell you, it's just south of $0.5 billion. And so we haven't laid out anything in terms of detail on that. But we're really, really excited about the way that project's come together. And the capital team and the projects team has continued to find ways to take cost out of that project as well. And that -- and by the way, that includes an expansion for our gas system and the connection of that and there's some significant expansion for the oil side system of that and which will pay benefit for the future and as well an expansion of our [indiscernible] facility to be able to handle all of this rich gas.

So lots of lines of profits between the gas transportation, the oil transportation and the processing of that gas. And so we're really excited about the returns and the way that area is paying off and I would also add, there's several other large prospects out there that are looking very fruitful as well. And so the story could be even better out there in terms of growth over time. So that has turned in to be a great project.

And our deepwater construction team has really done a nice job. We're well into that project at this point. As you know, we had a reimbursable agreement with Shell. So we're well into the details of engineering. And in fact, have already bought and had all delivered -- all of the deepwater pipe for that project is now -- was built in the U.K., but it's now here in the U.S. So great efforts by the team. Mike, do you want to take the Regional Energy Access?

Micheal Dunn

Sure, Alan. Just as a reminder, on Regional Energy Access, we made that FERC filing back in March, where the project initially expected an environmental assessment to be completed for the project, but with the changing atmosphere at FERC, they were basically pushing all of the new projects that come in the door and even some that were already there prior to Chairman Glick becoming the Chairman.

To go to an environmentally-backed statement will take a little bit longer for us. It shouldn't have an appreciable impact on the overall project schedule. We would still expect to have a FERC certificate next year in 2022 and then could begin construction later that year. We still plan for a Q4 2023 in-service date for the project as we stand today.

Alan Armstrong

And Micheal, I would just add on the deepwater on the well project. That pipe and a lot of the engineering that's gone into that and a lot of the specialty fabrication is already in this year's capital budget. So a lot of the materials and pipe has already been paid for or is included in this year's budget. So they'll pile it on to the next couple of years' debt.

Operator

At this time, there are no additional questions. I'll turn the call back over to Alan Armstrong from Williams.

Alan Armstrong

Okay. Well, thank you all very much. Continued great success here in '21. Teams continue to hit on all cylinders. And importantly, even though we've got great growth here in '21, what we're really excited about is how we're positioned now for the future with a number of very important drivers for growth here in the future that will show up in '22 and beyond. So really setting a nice platform for growth for our business for years to come. So we thank you for your attention today and the great questions, and we'll speak to you again soon.

Operator

Ladies and gentlemen, this does conclude today's conference call. You may now disconnect.