Good day everyone, and welcome to the Williams Q3 2021 earnings conference call. Today's conference is being recorded. At this time, for opening remarks and introduction, I would like to turn the call over to Mr. Danilo Juvane, Vice President of Investor Relations. Please go ahead.
Thanks, Amir. 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 Chandler, will speak to this morning. Also joining us on the call 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 we reconciled to generally accepted accounting principles, and these reconciliation schedules appear at the back of today's presentation materials. With that, I'll turn it over to Alan Armstrong.
Great, thanks, Danilo, and thanks to all of you for joining us today. We do have a lot of good news to share with you today, but let me just start by saying that our long-term strategy of connecting the fastest-growing natural gas markets with the best supply areas continues to deliver exceptional financial results, as demonstrated by these higher-than-expected Q3 financials. As John will walk through in just a moment, we achieved all-time record results in the Q3 with our adjusted EBITDA up 12% compared to the same period last year, driven by growth across all three of our major business segments.
Given our robust performance- to- date and continued strong fundamentals, we are raising our 2021 EBITDA guidance midpoint for the second time this year to a level that is now 8% above our realized 2020 results, which I'll remind you came in above expectations last year in a very challenging backdrop. Not only did we deliver more on our financial performance this quarter than we expected, but we continued to make strides in executing on key projects and transactions that give us a clear line of sight to sustain growth for many years to come. We'll talk a little bit about that today. For right now, let me turn it over to John to provide you some insight into the drivers of this all-time record quarter for Williams. John?
Thanks, Alan. First of all, just what an incredible quarter we had. 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, significant contributions from our upstream operations in the Wamsutter, and the benefit of higher commodity prices in our West segment. The positives were offset somewhat by slightly higher operating expenses resulting from increased incentive compensation expenses reflective of the strong performance that is unfolding for the year. You can see that strong performance in our statistics on this page. In fact, once again, we saw improvements in all of our key financial metrics. First, our adjusted EBITDA for the quarter was up $153 million or 12%, setting a new record.
We've seen a 10% increase in EBITDA year-to-date. We'll discuss EBITDA variances in more depth in a moment. Adjusted EPS for the quarter increased $0.07 a share or 26%. AFFO also grew significantly for the quarter of $217 million or 25%. AFFO, I'll remind you, is essentially cash from operations, including JV cash flows and excluding working capital fluctuations. If you put our year-to-date AFFO of $3 billion up against capital investments year-to-date of $1.2 billion and dividends year-to-date of $1.5 billion, you can see that we generated over $300 million of excess cash year-to-date. Included in those capital investments I just mentioned were $307 million of maintenance capital.
Also, you can see our dividend coverage based on AFFO divided by dividend is a healthy 2.17x for the quarter. 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 currently sit at 4.04 x net debt to EBITDA. You'll see later in our guidance update in the deck that we've moved our guidance for the year from where we were at less than 4.2 x for the year now to around 4 x at year-end. Really strong performance for the quarter and the year, and the fundamentals are set up for a good Q4 and a very good 2022.
Now let's go to the next slide and dig in a little deeper into our EBITDA results for the quarter. Again, Williams performed very well, realizing $153 million or 12% higher EBITDA. Our upstream operations added $55 million to adjusted EBITDA this quarter. This is almost entirely from the Wamsutter Upstream acreage. Production from the combined assets, mostly from Wamsutter, totaled 232 million Mcfe a day for the quarter net to our ownership. Again, the Haynesville Upstream acreage produced very little EBITDA, given it has only a small amount of existing PDP reserves, and therefore, it'll take a little time before we see new production, and therefore, EBITDA coming from those assets. Our transmission Gulf of Mexico assets produced results that were $8 million more than the same period last year.
New transmission pipeline projects added $24 million in revenue versus the Q3 of 2020, including the Southeastern Trail project that went into service in the Q4 of last year and a portion of the Leidy South project that also went into service in the Q4 of last year. You can see this evidenced in the growth in our firm reserved capacity, which is up 4% from the Q3 of last year. Offsetting this somewhat was Gulf of Mexico revenues that were down due to incremental impacts from hurricane shut-ins during the quarter from Hurricane Ida in comparison to the hurricane impacts in the Q3 of last year. Just so you have a number there, the incremental impact this year was a negative $5 million versus the Q3 of last year on hurricane impacts.
In addition, the transportation revenue increases were offset somewhat by a slight increase in operating expenses, 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 470 million a day or 5% this quarter versus the Q3 of 2020, while processing volumes grew 20%. The volume growth was predominantly at our joint ventures 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 at larger pads.
Just to be clear, because we do not operate Blue Racer Midstream, those volumes are not included in the volume statistics I just quoted. As a result of these increased JV volumes, our EBITDA from equity method investments improved by $45 million, which also included the benefit of additional profits from Blue Racer Midstream, again, due to our additional ownership we acquired in mid-November of last year. Otherwise, in the Northeast, higher revenues from higher processing volumes were offset by higher expenses, again, with a significant portion of those expenses being related to higher incentive compensation accruals. If you go to the West, that segment improved by $48 million compared to prior year. $35 million of this increase is related to higher commodity margins due to higher natural gas and higher NGL prices.
Otherwise, the remainder of the uplift in EBITDA comes from lower operating costs due to lower maintenance fees and due to the absence of legal costs and small asset write-offs that occurred in the Q3 of last year. Revenues for the West were only up slightly compared to the same period last year. Now, there are a number of big items that go opposite directions in revenues that I'd like to point out. First of all, for example, remember that we lowered our gathering rates in the Haynesville this year in return for undeveloped upstream acreage from Chesapeake in the South Mansfield area in the Haynesville. The resulting gathering revenue decrease from this during this quarter was more than offset by rate increases in the Barnett and the Piceance, where our gathering contracts allow us to participate in the upside when prices are higher.
Also last year, our partner on Overland Pass Pipeline was paying us a deficiency fee to allow them to pull volume off of OPPL. Those deficiency fees do not exist this year. However, the absence of those fees are being offset by fees from higher gathering volumes otherwise. To that point, overall gathering volumes in the West were up 1%, with higher volumes in the Haynesville and the Piceance being offset somewhat by lower volumes in the Wamsutter and the Barnett. Then finally, the Sequent segment produced near flat adjusted EBITDA for the quarter. Sequent traditionally makes a significant portion of its profit in the first couple of quarters of the year in the heart of the winter season, and therefore did not realize profit for the quarter.
Sequent does have a significant portion of their transportation capacity hedged with basis swaps, as well as their storage inventory hedged with nine-month positions, which of course led to the large $277 million unrealized mark-to-market loss on those hedges this quarter as prices increased and as basis differentials widened in some markets. This of course means that the intrinsic value of our storage and transportation positions have gone up significantly as well. You'll see a significant portion of that value realized in the first half of 2022. Now to go to the year-to-date results. Our year-to-date results showed strong growth of $383 million or 10% in adjusted EBITDA. Many profitable things are happening across all of our segments.
First, I point to Winter Storm Uri, which added $55 million in profits to the West, and it contributed $22 million of incremental profits to our upstream results. In addition, our upstream operations otherwise have added an additional $83 million year to date, almost entirely from the Wamsutter properties. Our transmission and Gulf of Mexico assets are up $30 million or 2% better, with the increases 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 due to a Transco rate case decline following the rate case final settlement in mid-2020 related to just a few markets.
As a reminder, a majority of our Transco rates actually increased in 2019. In addition, expenses are higher this year- to- date, due to higher incentive compensation expenses resulting again from our strong performance. The Northeast G&P is up $124 million for the year, almost entirely driven by profits from our JV investments, again, namely from the Bradford Supply Hub gathering systems and our Marcellus South gathering systems. In addition, we benefited from increased ownership in Blue Racer Midstream. In total, gathering volumes for the Northeast are up 8% over the Q3 of last year, while processing volumes are up 22%. Then in the West, our West G&P is up, that we earned from Winter Storm Uri.
The $71 million increase is driven by higher commodity margins, higher gathering rates. These positives were offset somewhat by lower Haynesville gathering rates, which again were exchanged for upstream acreage and lower Overland Pass Pipeline profits from lower actual volumes shipped and the elimination of the deficiency payments that we were receiving in 2020. While we did see a 4% gathering volume decline year- to- date in the West, that was mostly offset by minimum volume commitment payments. Again, this is stacking up to be an incredible year for us.
You know, one other thing I do want to point out, we did pick up in some of the narratives from some of the analysts last night the view that our operating costs increased, and we did ourselves a bit of a disservice by not providing more information on our other operating segment, where our E&P upstream operations reside. Actually, if you look on the face of our financial statements, our operating expenses went up $73 million. 12 million of that came from Sequent, who, by the way, covered most of that with their profits. E&P went up $51 million on cost, but of course, they're making significant EBITDA, so they're covering that with their revenues. The rest was related to bonus expenses.
Our expenses actually, when you extract Sequent and E&P and the bonus costs are actually down otherwise. We actually are not seeing a significant expense increases. In fact, the contrary is true other than the bonus-related expenses. I thought I'd clear that up. I'll now turn the call back over to investor focus areas. Alan?
Great. Well, thanks, John, and we'll move on here to slide 4, covering key investor focus areas. Our natural gas focus strategy is delivering even better results than we expected in this high commodity price environment. Demand for natural gas in the Q3 was surprisingly inelastic against this higher than expected pricing environment. While we would prefer more moderate natural gas prices for our business over the long haul, the recent demand resilience highlights the near and long-term role that natural gas will play as a complement to growing demand for renewable energy and emission reduction in general. The past 18 months have demonstrated the benefits of our high-quality portfolio of contracts through which we've thoughtfully built a business that is durable in the down cycles, but exposed to upside potential when it is available.
This quarter's results show how meaningful that upside can be even after excluding our upstream results. Along these lines, we also have contracted our business over the years to be protected from inflationary environments, and we see additional upside potential in our G&P businesses due to contract terms that adjust our rates for inflation. In short, our business and its contractual portfolios are set up with the long-term investor in mind and are positioned to thrive through these cycles. Midpoint now residing at $5.525 billion, and that is 8% higher than last year's strong $5.105 billion of EBITDA. Of course, that was a feat by itself in the environment that we are in. We're really excited to show our durability in the down cycle and our exposure here on the positive side as well.
While the past few years have been characterized by lower commodity prices and reduced producer customer activity, among 2021 EBITDA and EPS guidance, the midpoint translates into a three-year CAGR of 6% on the EBITDA and 17% on the EPS. A three-year CAGR on our EPS now is 17% at that midpoint. Of course, this is proving up our ability to produce reliable and growing earnings under a variety of market conditions. Our financial results in 2021 continue to de-risk our balance sheet, which is now at about 4.0 leverage. Also of note, we recently issued $1.25 billion of 10-year and 30-year bonds at the most attractive interest rates ever issued here at Williams.
This is significant because we are now positioned to allocate capital to a variety of options that will provide compounding value to our long-term shareholder. To this end, we've continued to grow our stable quarterly dividend through our investors and remain steadfast in maintaining the long-term security of the dividend. Most recently, we unveiled our long-term capital allocation priorities, including a $1.5 billion opportunistic share repurchase program that has the potential to enhance shareholder returns beyond the dividend. Perhaps most unique to Williams, as we think about capital allocation, is the option we have to grow dependable earnings by investing in the modernization of our regulated transmission systems, which will both grow earnings and as well reduce emissions across our footprint. Next here, looking at growth.
From a project execution point, we continue to deliver on multiple fronts, including bringing online key projects such as Leidy South, which we are targeting to bring into full service earlier than projected, and importantly, before the winter heating season. While projects such as Regional Energy Access remain in the execution phase, we've continued to receive interest and demand for projects on the Transco system. Our two recently announced Mid-Atlantic expansions will add a little more than 500 million a day of capacity on the system. In the coming weeks, we expect to secure precedent agreements for another system expansion, bringing a total of three incremental expansion projects on Transco just here in the last half of 2021. Our natural gas fundamentals are not only supportive of our transmission assets, but also our G&P business continue to grow at a rate of nearly 10% U.S. gas production volume.
This, of course, was led by the Marcellus growth, where we are also growing at a rate that is almost double that of our competitors. You can see the layout of that in some slides we put in the appendix. With projects like Leidy South and REA providing takeaway out of the basin, we expect our gathering volumes in the Northeast to remain resilient. In fact, we expect to announce a system expansion in the basin soon. No constraint in the near-term is a deterrent there in our Northeast gathering area. Finally, on sustainability, as we think about sustainability both today and into the future, our highly reliable natural gas infrastructure is extremely well-positioned to continue replacing higher carbon fuels while supporting the growth of renewable energy and responsibly sourced natural gas for LNG export.
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. To this end, we are pursuing emerging opportunities like a hydrogen hub near our assets in southwestern Wyoming, and are evaluating a large-scale co-development of wind energy, electrolysis, and synthetic gas via methanation in the state of Wyoming as part of our recently announced MoU with Ørsted. Our solar initiative continues to move forward as we now advance the execution of now 12 projects on our systems, and those are, as we've mentioned before, large solar arrays that will provide power for our fairly large loads on our compression and processing facilities. Now, looking at our renewable natural gas efforts.
We set a 2021 goal of adding an incremental 5 million a day of renewable natural gas, and we now expect to exceed that goal. We recently signed an interconnect that should enable up to 10 million cu ft per day of a new source of RNG supply, bringing our entire RNG portfolio close to 25 million cu f t per day with in-service dates in the 2022 through 2023 time frame. A lot going on on that front. Team's doing a great job of making sure that we're capturing opportunities in and around our assets there.
We do remain steadfast in the view that natural gas will play a role in the world's clean energy future, and our latest efforts to advance responsibly sourced gas through the value chain will provide transparency on the sustainability of our operations and help to solidify the role of natural gas in reducing emissions. We're also pursuing sustainable investment opportunities and are pleased to be partnering on two strategies with Energy Impact Partners, an investment firm that makes venture and growth investments in companies that are optimizing energy consumption and improving sustainable energy. Williams is among the first midstream investors in the platform, and we're expecting to facilitate diverse investment opportunities that reduce emissions and advance our ESG goals. Finally, our ongoing focus on sustainable operations continues to deliver strong results that are being recognized by our key rating agencies in this space.
Williams sits in the top quartile for our industry, with rankings that reflect the dedication of our team toward doing the right thing from an ESG perspective. Here in closing, a lot of really positive things to report on this quarter, demonstrating that our intense focus on 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 pipes like Transco, Northwest Pipeline, and Gulfstream are in the right place and in the right markets. 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.
The triple punch of benefits provided by American-sourced natural gas must not be understated as we work to accelerate our clean energy future around the world. As we work to balance sustainability and climate goals with growing energy demand, natural gas will remain a key component of the fuel mix and should be prioritized as renewables complement to more aggressively displace more carbon-intensive fuels around the world. Natural gas does provide industry and manufacturing here at home. Williams transmission and storage networks are extremely well positioned to aggregate and bring scale to multiple emission reduction opportunities, taking out higher carbon fuels while supporting renewable energy and emerging opportunities like hydrogen and carbon capture.
In closing, we produced tremendous Q3 results. More importantly, we have an unmatched platform to continue to deliver growth and lower emissions at the same time. We look forward to helping our customers and stakeholders meet their goals in an environmentally and financially sustainable manner. With that, I'll open it up for your questions.
Thank you. We will now begin the question-and-answer session. To ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound or hash key. Please stand by while we compile the Q&A roster. Your first question comes from the line of Jeremy Tonet with JP Morgan. Your line is open.
Hi, good morning.
Hey, good morning, Jeremy.
I just want to kind of touch on the strong results this quarter and how we should think about that going forward. If I look at the guidance raise, it doesn't necessarily seem that all the benefits that materialize in Q3 fully translate into Q4. Just wondering how much of this is sustainable, how much growth, you know. Is this a level that could be built off of into 2022 EBITDA? Just trying to get a sense for, you know, what's recurring here in the strength this quarter.
Yeah, Jeremy, thanks for the great question. You know maybe just speaking to a few pluses and minuses from Q3, one of those that you heard John mention is we did take an accrual for bonuses for the year and both on our long-term incentive comp as well. I see a lot of people adjusting that out of their adjusted EBITDA. We don't adjust that out of our EBITDA. Our long-term incentive comp and we did take some accruals for that as well as our annual bonus, which obviously with this kind of performance, we'll be paying out. That was a hit to the quarter that would be negative. On the other side of that, we had about $24 million, I believe, of a pricing increase on our NGLs and inventory.
To the degree that that doesn't increase again, that you know that would offset against that positive that shows up in the quarter. That's kind of a non-operational issue, if you will. We have to price that inventory up. To the degree that NGL prices don't move again, then that wouldn't show up. That's a couple of, you know, one positive, one negative. I would just say, you know, we pay attention to the forward strip when we think about our forecast and our guidance. Obviously, you know, those are backward dated as we sit here. You know, our expectations would be the same moving forward as it relates to the E&P business.
I will say that, you know, that's not a huge driver of our business, obviously. You know, it's pretty measured as you can see. It will become larger in 2022 as the Haynesville starts to get developed, that will be a net positive to where we will build larger sensitivity to gas prices in 2022 as the Haynesville starts to be developed. So, you know, I would just say we're. We know this was a good quarter in terms of pricing and we're not gonna build our business in a way that's just sustained off of high commodity prices. That's, you know, hopefully evident in how we forecast our business as well. Nice to take the winnings when they come to us, but we're not gonna forecast our business around that. Obviously, if prices do stay high, then you know we'll certainly see the rewards from that.
Jeremy, just, you know, as it relates to this year's guidance, you know, obviously, I think by our nature, you probably know we're somewhat conservative on how we, you know, do things. That's probably a bit of that's embedded there. Also we left ourselves some flexibility that relates to the Q4 . If we wanted to accelerate, for example, gifts to our foundation, you know, our strong results gives us flexibility to do some things like that would be expenses we'd otherwise incur next year or the year after. We do have some flexibility and some capacity to do things like that.
Got it. Moving along here, I guess the next question I have is in the Build Back Better Act here. Just wondering what implications you see for your business here. It seems like it could be different things, you know, 45Q being higher, you know, some other energy transition, you know, initiatives in the bill and at the same time, 15% minimum tax. Just wondering if you could walk us through some of the pluses and minuses that you see in the bill, if passed as written, how it would impact WMB.
Yeah. Well, you know, certainly, we would keep our eyes on the alternative minimum tax, and I'll let John speak here in a minute to that. I think as it relates to things like increasing the 45Q amount, obviously that would be positive for us, particularly as we think about utilizing our infrastructure for carbon capture and in places like the Gulf Coast where we have a pretty sizable footprint that extends out to some of those water drive reservoirs that would be key targets for carbon sequestration. So, you know, lots of positives, I think, in that area. On the methane emissions issue, we are really encouraging that to be done in a way that rewards those who reduce methane emissions.
We think, you know, we think it's smart to continue to put focus on methane emission reductions, and we're extremely well positioned for that. But we would much prefer one that rewards the good actors in that and not just a pure tax, but one that does incent those that have been working to reduce their emissions. We think we stand out in that regard, and we think that would be a net positive for us if it's positioned that way. Obviously, you know, we think that makes sense when you're talking about the lowest carbon content hydrocarbon. It seems a little bit odd that you would just put a pure tax on that when it has such an ability to help reduce emissions around the world.
We're hopeful that, you know, we'll get to a wise place on that. We think that actually could, you know, be positioned in a way that could be somewhat of a positive for us. We would look forward to that. I think that's, I don't know, Chad or-
Yeah, Jeremy, this is Chad. Just on the last note on the hydrogen front, the hydrogen incentives as currently drafted would be, I think, a good complement to our current strategy. We've been working closely on that front and think that would be supportive as well as supportive of our goals on that front.
You know, just as it relates. Just as it relates to the alternative minimum tax, yeah, there's still a lot left to be discovered there. I would tell you, I think on balance, obviously, we prefer a lower corporate tax rate and an alternative minimum tax than the inverse. AMT is just timing of cash tax payments, higher tax rates forever and permanent. You know, if that's where we land with AMT, that's not terrible for us. The question is gonna really be around NOL usage against. Under the old tax scheme when we had an alternative minimum tax before, you could take up to 80% of your NOLs against your income for the alternative minimum tax calculation. That's not clear in the current legislation.
You know, as we've thought about it, we've assumed, let's say we could take 50% or take 50% of our income out through usage of our NOL\s. You know, that alternative minimum tax would be not that sizable for us. We'd probably be able to cover it with excess cash flow. So that's how we look at it now. But just to be clear, there's still a lot of questions around the usage of it—NOLs, you know, going forward. Can you use 50%, 80%, or use them at all? That's still yet to be understood.
Got it. Thank you.
And, and just-
Sorry.
-you know, just an additional fact there, you know, we're carrying forward $4 billion of net operating loss NOLs.
Understood. Thank you.
Your next question comes from the line of Christine Cho with Barclays. Your line is open.
Thank you. Good morning. Maybe, with the outperformance this year and leverage tracking below your target, how should we think about the execution of the buyback that you announced a couple of months ago?
Yeah, Christine, thank you for the question. I kind of expected we would get that. I would just say that, you know, we've been pretty clear about how we're thinking about that, and it is a multiple of the cost of our 10-year debt cost in the market for our ten-year debt cost. That yield continued to go down and therefore moved away from that multiple during the period since we announced the buyback.
I would say as we don't make investment in that or if we continue to invest in earnings, either one of those will continue to drive our credit metrics to a more positive place, which will drive down the 10-year debt, which then would lower the yield at which we would invest in. I think it's pretty natural in terms of how that'll occur. If money is flowing metrics, you would expect our 10-year rate to continue to improve, which we would hit a point at which we would be steady. If that price moves to that zone, we'll be anxious to be taking advantage of that if that occurs.
Nothing's really changed from our perspective on that other than the fact that our amount of free cash flow continues to expand and accelerate. But other than that, nothing's really changed here since we announced that. You would be okay with just having your leverage trend below four times if the opportunity to buyback stock didn't present itself?
That's right. I would just say, though, you know, as we've mentioned before, obviously the one kind of unique option we have is continued investment in the rate base in a way that modernizes and reduces emissions on our system. You know, that's not a hair trigger, so to speak, because we have to plan for that. That's a permitting process that we don't snap our fingers at. That's something that takes time, but that's obviously another place that money will flow through our capital allocation process.
That actually was my follow-up question. Around the modernization program, can you just remind us how this works, how much you spend per year, the returns, how quickly you can earn on the spend? And then I guess just sort of, as you mentioned, what kind of regulatory process we're looking at?
Michael, you want to take that?
Yeah. Hi, Christine. It's Micheal. We're working on both fronts with Northwest Pipeline customers as well as Transco customers and working to enact a tracker if we can get to a position with them. If we can't, we would, you know, go through our normal rate case process to seek recovery of those emissions reduction projects. We believe we've got north of about $2 billion or so that we could invest between both Northwest and Transco on those projects. That could be a very long-term program, you know, over maybe six years or so.
If you start doing the math on that's $300 million-$500 million a year potentially that we could deploy there, depending on the spend profile and how many projects we wanna take on at a time.
If you don't, you know, come to, like, an agreement with your customers, would you have to recover it through a rate case, or is there something, you know, quicker?
No, we would have to go through the rate case process. You know, that's obviously one of the reasons why we would like to have a tracker to accelerate that recovery and not have to go through the thrash of a rate case, and the disruption that occurs with the customer base there. We're prepared to do that if we need to, but we would certainly like to do it through a tracker mechanism, very similar to what many of our customers are doing in their jurisdictions.
The returns?
Returns would be very similar to what our regulated returns would be on either Transco or Northwest Pipeline once those rate case outcomes are known.
Okay, great. Thank you.
Christine, I would just add there, just to remind folks on when we do file those rate case, we still do go ahead and raise our rates. We don't have to wait for the settlement in rate case once we file those rates. That, as you'll recall, we hold that in reserve sometimes pending that settlement, but we do have the authority to go ahead and charge the higher rates.
Right. Thank you.
Your next question comes from the line of Shneur Gershuni with UBS. Your line is open.
Hi, good morning, guys. I kind of wanted to start off a little bit here. You've had a strong performance last year, strong performance this year, or heading into the end of the year, you should be based on your guidance. You've had a growth target kind of in the 5%-7% range. Kind of the question I have is, does any of the performance in this year kind of take away from next year? At the same time, you've announced several Mid-Atlantic projects. You intimated that there's another one potentially coming in your prepared remarks.
I was just wondering if you can share some detail about the return expectations of these new projects, and are they high enough to help drive growth forward? Is there a backlog of more of these projects that we can see more announced over time?
Yes, Shneur. Thank you. First to the projects, I would just say our returns, you know, generally continue to improve. You know, one that's kind of been, as we've said many times, there's kind of a double-edged sword about the difficulty of building projects. It certainly has, I think, been detrimental to the country and the industry overall, but to the degree that you're the incumbent with pipe in place and you can expand those via brownfield, it effectively expands your return opportunity in that regard. I would just say that, you know, the returns in general, not saying that they always will be that way, but in general, these returns for these Mid-Atlantic projects that we're mentioning are at least as good as Atlantic Sunrise or better.
That's kind of the way to think about that. REA is an attractive return project as well. In the question of how many do you have? You know, we keep the slide updated in there about the number of projects in development in our appendix, and it always looks like it's the same old slide, but in reality that we are moving projects from development into execution, and we have new projects flowing in there that are keeping that pipeline very full. I would just tell you, we don't see much backing off in the way of opportunity, for expansions of our transmission systems and with that obviously we'll flow gas from the low-cost producing areas and we're well positioned to capture that on the gathering side as well.
Despite what you know you might think when you listen to the media and the rhetoric, it's certainly not showing up in people's reluctance to make long-term commitments to our transmission systems for supplies that they know they're gonna need, whether that's to back up renewables or whether it is a base load, that the people and our customers certainly understand that it takes time to build these projects and that it takes long-term commitments to get them built, and that's what we're continuing to see.
Okay. We really appreciate the color there. Maybe if we can return to the return of capital priorities. You know, in your response to Christine's question, I think you were fairly clear in terms of you were looking for the opportunities to execute. But you know, at the same time, your balance sheet is obviously doing better than expected. There's a priority over growth, kind of how we discussed in the last question here. Just kind of curious if one of the other arrows in the quiver, shall we say, would be around a dividend. Is there any thoughts around a dividend step up or specials, or is there a different payout ratio that we should be thinking about as part of your return of capital strategies?
Yeah, I would never say never, but I would say right now we intend to just continue to maintain that steady growth and continue to maintain the growth in our dividend that's commensurate with our cash flow growth. And obviously to continue to maintain that high level of coverage. The security of the dividend there. We don't expect anything special. If we did, you know, some kind of asset sale, and by the way, don't run off with that one because there's no intent behind that one. Say if it was something special or some kind of structure that delivered a bunch of cash, then we would consider that. Right now I think you should just expect steady growth in our dividend that's well covered and very durable.
We think, you know, this is the kind of business we've built a long-term durable business as I think we've proven out. We think that our yield on our dividend ought to, you know, continue to trade down to reflect the durability and the growth within our dividend. I think it's, you know, a pretty hard dividend to compete with, frankly, given its security and the growth in it by both utility sector and within our peer group. We think eventually we'll be rewarded for that.
All else equal, buybacks is probably the preferred avenue at this point if you hit investor return section.
Well, again, I mean, we've laid out the options. The market will tell us whether we need to buy back shares because it's presenting an opportunity or not. If it does, the value will continue to generate through these other modes.
Perfect. Thank you very much. Really appreciate you calling today.
Line of Praneeth Satish with Wells Fargo. Your line is open.
Thanks, good morning. You touched on this earlier, but if we assume that the Biden administration passes regulations on emissions, what exactly could that mean for your business? I guess how further ahead are you than peers? Do you think this helps you win new customers or pull volumes from competitors?
Yeah, you know, I don't know exactly where we stand up against peers. I know where we stand on the ONE Future measures and, you know, we're almost orders of magnitude lower than what's required for our elements of the sector. Again, that ONE Future is a 1% all the way from the E&P space all the way through the LDC or to the delivery to burner tip. We're, you know, we're excited to be a part of that. There's a certain percentage of that 1% that's allocated to our sectors of the business. In those cases, we are way below, and as I said, orders of magnitude below that. We think we stand well, but we really don't, you know, we don't know exactly where other competitors might stand on that.
We need good, reliable operators in this space. Ernest Moniz, back when he was Secretary of Energy, really made it clear that, "Hey, I love this industry. I think it has a lot to offer from an emission reduction standpoint, but you guys have got to get your methane emissions. That's going to be your Achilles heel if you don't go after this." We've been on a mission to reduce that. I think we're extremely well positioned if the methane emissions are positioned right. I frankly think it's a real positive to make sure that we're reducing flaring, we're reducing emissions and VOCs from tanks in the field. I think all these things are very positive for our industry, and we certainly intend to continue to be a leader in that space.
Got it. I'm wondering if you could just give us a sense of how large one with Ørsted as part of that JV or MOU. Either on a tons per day basis or absolute dollar cost basis, just trying to get a sense of how big the projects are. Then just tied to that, if the hydrogen subsidies that are part of your hydrogen development plan.
Yeah. Hey, this is Chad. Thanks for the question. Maybe starting with your last question. Yes, the incentives will be supportive in accelerating project opportunities incentive structure and really need an incentive structure to help support getting projects jump-started. I would also say that it is still, you know, early days on the hydrogen front. We're at the pilot stage. I would characterize it as if things prove out, costs continue to come down, which we expect they would, the incentives get passed. You know, in Wyoming, for example, develop an energy hub in Wyoming in partnership with Ørsted and others. You know, you could envision a very large wind power production facility, you know, 300 MW-500 MW, if not larger.
There's a tremendous wind resource in Wyoming that hasn't been fully developed because it's not easy to build electric infrastructure to deliver that to other parts of the country. We could build a very substantial wind power generation platform tied to you know several hundred megawatt of hydrogen production that we can move through our existing infrastructure to customers across our footprint. We believe we could move through our existing infrastructure to customers across our footprint. You know those are big ambitions. I would tell you again, it's very early innings, but the pieces are coming together and put some projects online that I think will demonstrate. That gives you just one example. We're looking at others across our footprint, but that's one example of where you know we think we can get to scale.
Great. Thank you.
Your next question comes from the line of Spiro Dounis with Credit Suisse. Your line is open.
Hey, good morning, team. First question just on inflation from two different angles. First and then alternatively, I imagine a lot of your com- I'd probably have some sort of escalators in there tied to CPI or PPI, sort of upward pressure on fees as we get into next year in this environment.
Yeah. Good morning. This is Michael. We're watching the supply chain issues. We got in front of the supply chain concerns early on with treating chemicals and lube and things of that nature to make sure that we had what we need to operate the business. In fact, we are seeing price increases. Fuel, diesel, gasoline prices are up. It's a really small component of what our overall expenses are in the business, and we feel like it can be managed appropriately. As you mentioned, the bulk of our gathering and processing agreements do have escalators in them, so we are protected there on the gathering and processing side.
We've been in very good shape for a number of years in managing that, and I suspect our teams will continue to do a great job at that going forward here and, you know, take advantage of opportunities where we can to control our costs. We will see some increased costs, and there's no doubt about that. You know, the escalators that we have, there's various escalators that we use in the gathering and processing agreements, and I believe it would definitely cover the expense increases that we'll see.
Got it. Thanks for that color, Mike. Second question, just switching gears slightly to the Permian. I know you're all focused on gas basins, and that certainly served you well. I know at one point you had sort of considered Bluebonnet as sort of a pipeline out of the basin. Obviously, I think we're seeing that basin tighten a lot faster than we all expected with some of your peers talking about another pipeline potentially as early as 2024. Just curious on any interest levels in the Permian in general and how you're thinking about Bluebonnet and your competitive nature there.
Yeah. You know, we've certainly positioned ourselves well to take part in projects that come up. I would just tell you so far, you know, we like the risk mitigation that we get out of the kind of projects that we do, which are more market-oriented and not. They've either already been written down or in construction, not yet in the Permian. I would just say, you know, it's always an issue of risk-adjusted return, and those are big risks on the back end of a pipeline that are easy to ignore on the front end, but hard to ignore on the back end.
We think about our business on a very long-term sustainable basis, and longer term contracts and ones that we know that the shipper's in there for the transportation for the long. I'm not telling you that we won't be looking to take part, but the returns would certainly have to be competitive within our capital stack for that.
We have been expanding the capability for Transco to receive volumes from the Permian. You know, if you think about our project strategy, if you look at the projects that have been approved, the projects we focus on, we connect directly to demand. That is a very, you know, strong, sustainable, I think, strategy. As Alan mentioned, typically the demand contracts are very long tenure. You know, we'll keep an eye on the Permian. But as he mentioned, you know, unless we can tie those projects to long-term contracts or to demand that we know will be sustainable, then we will probably look towards other parts of the system where we can kind of fit that bill.
Got it. Appreciate the color, guys. John, congrats on the-
Thanks.
Your next question comes to Tudor, Pickering, Holt. Your line is open.
Morning. Just circling back briefly on the Wyoming Energy Hub, is that an area where Williams would look to own a stake in the wind and electrolysis facilities? Or would you prefer to lease the surface acreage to Ørsted and participate further downstream on the transportation side?
Yeah, I think it's. You know, we're evaluating a lot of different possibilities. I mean, clearly, we're gonna focus on where we have strength and capabilities. You know, the strategy there is to demonstrate that our infrastructure can be a part of the energy systems for not just the next 10 years, 20 years, but for the next 100 years. You know, we're gonna stick to what we're good at. We're gonna partner with really strong, capable, partners like Ørsted and others. I think we certainly think we have a very unique set of skills and infrastructure to make these projects possible. We're gonna wanna make sure that we participate, you know, where it makes sense. I think it's a little bit early on to understand exactly where we're going to be putting our investment.
You know, clearly in the Ørsted announcement, we're not a wind power company. We're not an electrolysis company, and we're gonna need technology providers to work with us. Whether or not we invest in those parts of the value chain, I think we will stand prepared to do that if it's a smart, you know, place to invest in what we're doing on the solar front. It's what we're doing in certain RNG opportunities. But it's still pretty early on to figure out how all those pieces come together. We're constantly evaluating that.
Got it. Just briefly, in the West, it looks like NGL transportation volumes stepped up a bit more than NGL production. Are you seeing a rebound in volumes coming into Overland Pass from the north or anything else to point to there?
Yeah. Well, we're seeing some production increases from our assets out there. I'm not gonna talk too much about the third parties coming in there, but we are seeing some really good uplift from our processing plants, and ethane recovery has been off and on throughout, you know, the summer and coming into the fall here. We're seeing an opportunity to bring in additional ethane into the systems as well. We were able in the Wyoming area, even though this should have showed up in the production volumes coming out on the C3. I think it's always a good thing to pay attention to the C3+ volumes because obviously the ethane comes in and out based on pricing, and C3+ is kind of a better indicator of what's available on a regular basis.
I would say the Patrick Draw facility in Wyoming that we picked up earlier in the year, which was an adjacent plant to Echo Springs, shut down, and we were able to pick those volumes up, and those volumes came directly into our system as well. We also picked up some volumes off of a competitor pipeline there during the bankruptcy process from Southland, and those volumes flowed into us as well. There at Echo Springs, our Wamsutter facility, we've really been able to pick up the equity volumes that are coming to us. Some of that equity would have gotten produced, some of it would have gone on a competitor pipeline. All of that is now coming into our pipeline. That's some of that pickup you're seeing.
Great. I appreciate that.
Your next question comes from the line of Chase Mulvehill with BofA. Your line is open.
Hey, good morning, everybody. I guess, you know, you spoke briefly about responsibly sourced natural gas during the prepared remarks, but just a quick follow-up here, and like to ask if you're seeing kind of more interest from, you know, LNG liquefaction operators or really kind of more interest from, you know, utility customers. You know, I guess if you look at this responsibly sourced natural gas, like, what's really the constraint to seeing quicker, you know, market adoption of responsibly sourced natural gas?
Hey, this is Chad. Thanks for the question. Yeah. What I would say is that we are seeing strong interest from both LNG off-takers and utility customers. We have a wellhead to water and a wellhead to burner tip strategy with respect to responsibly sourced gas. We haven't been extremely explicit on our plans in this area because we've been working them very hard and want, as Alan mentioned, to have a very credible solution in place. I will tell you that we're clearly seeing a need within the marketplace to demonstrate not only within our footprint, but to work with our upstream partners and to work with our downstream customers to really track the full lifecycle emissions footprint of the gas that flows through our systems.
We will be announcing, you know, several solutions that we are going to be focused on delivering for our customers. We have been in discussions with several of our customers where we think we can marry the solutions that we're developing with our producing partners' efforts, as well as our LNG customers and our utility customers. We wanna be able to shine a very credible light on the emissions footprint of the products that we move, the gas that we move through our systems, and then show how we are going to drive down those emissions over time. Just circling back to Alan's comments also, you know, the Transco system is the largest, most flexible pipeline system, you know, in the United States.
We have the benefit of having multiple lines in our right of way. We can do a lot with that system to demonstrate a lower emissions footprint today and to show a continually decreasing emissions footprint over time. We wanna make sure we can do that in a very credible manner. You know, I do truly believe we are working with the Sequent team to make sure we can market that gas as a credible, responsibly sourced product. I mean, we are seeing a real intense focus on that front.
To the point where we've even had meetings with utility customers that have told us they are looking at the midstream providers to understand the emissions footprint of their potential gas supply, and they're gonna factor that into their decisions with respect to how they source their gas. We think that sets up very well for us, again, because we've got, I think, the most modern, most efficient system, you know, in the United States.
Quick follow-up on Sequent. I guess you know I guess first on responsibly sourced natural gas, you've probably got a better view than most people. Are you seeing you know responsibly sourced natural gas get a premium out in the market today? If not, what do you think will be the catalyst where responsibly sourced natural gas will actually start getting a premium out in the market?
I wouldn't think of it in terms of premium. I think of it in terms of the demand for our, you know, space is gonna continue to drive, I think, the responsibly sourced gas, whether you consider that to be a premium or at some point if it becomes the competitive cost to play. I think it will reflect in natural gas prices and in demand for natural gas. There have been a few marketed RSG products out there, and they've maybe, you know, attracted a small premium. I would also say, though, I don't know that no one has yet truly tagged an RSG product from wellhead to water, wellhead to burner tip in a way that I think, you know, can be credibly marketed.
We don't think of it in terms of premium. We think of it in terms of this is gonna be a differentiator for what we can provide to our customers and therefore, you know, support their goals as well as our mission goals.
Yeah. I think, you know, in the current environment, you should think about it in the context that somebody's gonna sign up for a long-term supply. Even if that is an indexed price supply that's competitive in the market, they're gonna wanna know that that's a supply that is not gonna have a negative connotation with it. I would say when it comes to doing long-term contracts at index pricing, that people are gonna be asking those questions. The tide right now, as we say, the tide's gonna go to the runner, so to speak, to responsibly source gas to the degree that somebody can prove that up or demonstrate that they're on a path to be able to prove that up. I think that's about as far as it's gone at this point.
I think it's certainly something. You know, I think there's pretty strong support across the industry for making that more of a determinant in the marketing space, and we certainly wanna be a part of that. It's gotta be credible, reliable, and something that's got good, strong data behind it, that ultimately could perhaps be even traded. That's what we're focused on.
All right. All makes sense. Appreciate the color. I'll turn it back over.
Our final question comes from the line of Sunil Sibal with Seaport Global. Your line is open.
Yes. Hi, good morning, folks, and thanks for squeezing me in. My first question related to the $1.2 billion of high return growth projects that you highlighted in your capital allocation framework. I was kind of curious, you know. I think you talked about some big projects in Gulf of Mexico and then obviously on the gas side, Mid-Atlantic projects. Are there any other big buckets we should be thinking of when we think about that $1.2 billion annual spend?
Yeah, I think, you know, I think that pretty well got it captured. I think the $1.2 billion on normal capital spend is gonna go first to the big projects on Transco, some of which we've mentioned today, our continued gathering system expansions, even though those are more limited. We're really excited about the millions of dollars we're investing right now in the deepwater Gulf of Mexico to support big finds like the Whale prospect. The deepwater Gulf of Mexico is gonna be a real driver of growth as you look out three years.
Beyond that, as we've mentioned many times, investing in the modernization of our rate base, which will come with emissions reduction along our systems and about $400 million of solar projects that we are moving rapidly through the development stage right now and starting to move towards execution on those projects. Those are kind of the primary drivers. That hasn't really changed a whole lot. I would say some of the projects on Transco are moving, you know, up from our development list into execution list. Other than that, really not a whole lot has changed since we laid out that capital allocation program.
Okay. Got it. One thing related to that. Is 3.5x-4x kind of leverage level the right way to think about the additional debt, which could come with those kind of capital spend?
I would just say, you know, depending on what happens with the price of our stock versus the cost of our debt will dictate a little bit of that. Said another way, if the price of the stock came down or the yield came up in a way that met this multiple of our 10-year debt, then money would go towards buying back stock and we would be running at the higher end of that range. If that doesn't occur, you'll see that drift down depending on how much we allocate towards the modernization projects that we've talked about. Those are kind of the immediate variables that we'll be navigating between.
I would just say it's a pretty strong multiplier effect as our EBITDA continues to grow, and we continue to invest in earnings projects, and our EBITDA continues to grow. That move down on the debt metric starts to move pretty fast. That is as you're seeing. That's not just in forecast, but you're seeing it in real time here as we continue to overperform on our debt metrics as our EBITDA moves.
Okay. Got it. Then one again related to that. When I think about, you know, your 10-year bond yield versus that dividend yield, obviously, you know, this year it's kind of come in a fair bit. You know, when you think about historically, it's still probably wide, and then obviously it's wide when you think about comparing it to, say, your regulated utilities or even, you know, S&P indexes. I was kind of curious, you know, how do you think about that metric's dividend yield versus 10-year bond yield spread? And how does, you know, what do you think is a normalized kind of a metric to look at when you think about your, you know, stock buyback decisions? Thanks.
Well, you know, from a debt yield standpoint, you know, it feels like we're probably gonna be hovering in this 2.5% to maybe 3% range for a while. You know, on the one hand, it feels like treasury rates are starting to move a little bit now, so we'll have to see what happens on that front. Credit spreads, though, I think, you know, we're performing obviously very well, and I think the sector is performing fairly well. So you've seen credit spreads tighten a little bit. We just saw that in our recent bond deal, just incredible demand for our paper.
I don't think we expect long-term rates, ten-year rates to be in the 2.5% range, but it doesn't feel like they're gonna be, you know, 3.5 or 4. That's the first part of your question, how do we see rates? You know, probably 3%. The other part of your question might be getting at what's the multiple, and we're not disclosing that. If that's your question on dividend yield relevant to that 10-year rate, that's we just don't feel it's smart really to signal to the market what that point is.
Got it. I thought I would try anyways. Thanks for all the color.
Fair enough.
Thank you. I will now turn the call back over to Alan Armstrong for closing remarks.
Okay. Well, great. Thank you all very much for joining us. Really excited to present the benefits of all the hard work of our employees around the company that have helped produce such a terrific quarter, both through continued great operations as well as a lot of the transactions that we've executed on this year that are driving some of this. It's a real pleasure to get to talk about the great performance that the organization's produced, and we look forward to doing that in the future many times more. Thanks y'all very much for joining us.
This concludes today's conference call. Thank you for participating. You may now disconnect.