Good day, everyone, and welcome to The Williams Third Quarter 2020 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, Investor Relations. Please go ahead.

Thank you, Cheryl, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Chandler, will speak to this morning. Also joining us on the call today are Michael Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our 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. So with that, I'll turn it over to Alan.

Great. Well, thanks, Danilo, and thank you all for joining us today. We are pleased to share the results of another strong third quarter. Williams once again exceeded its internal plans and investor expectations and showed just how durable this business can be against several headwinds, including a very active hurricane season in the Gulf. As you know, Louisiana bore the brunt of two significant hurricanes in Laura and Delta. And our operating teams in the area did a great job of staying safe, while minimizing the impact to our operations. As always, I'm impressed, but not surprised by the response effort to the region as Williams volunteers have donated supplies and manned staging areas in critically hit areas and really helped out those in need. Despite the hurricane impact, record Northeast gathering and processing growth allowed us to more than offset the financial impact of those multiple interruptions in the Gulf and produced the 19th consecutive quarter where we met or exceeded Street expectations. Our 2020 results year-to-date illustrate the stability and predictability of our business across a wide range of external factors. Everybody has gotten used to us being able to continue to produce on a normal basis, but this environment has really allowed us to distinguish ourselves in this more difficult market. Additionally, during this busy quarter, Williams announced its commitment and highlighted its ability to help in the reduction of emissions in a right-here, right-now way by becoming the first U.S. midstream company to set both near-term and long-term emission reduction goals. I'll talk a bit more about our climate goals later. But first, I want to highlight REX's performance in our Northeast G&P segment, and then I'll turn it over to John to walk through our Q3 results. So looking here on slide 1, we show that our Northeast Gathering and Processing segment handled record volumes in the third quarter of 2020 where our gathering volumes averaged over 9.4 Bcf per day across our operated assets in the Northeast. This was an 8.4% growth versus the 3Q of 2019 comparison and a 7% sequential growth over the second quarter of 2020. Strong growth in the rich gas areas drove even more impressive growth in our processing volumes and our NGL production. And you can see here the processing for the Southwest Marcellus and Utica areas was up over 17%, and NGL production was up nearly 24%. Each of these was a record performance for our Northeast gathering and processing segment. This strong performance is evidence of the attractive position of the Northeast business as gas market fundamentals begin to call on U.S. dry gas supplies. We are the largest gatherer in the most important and prolific gas-producing area, the Appalachian Basin. And within the Appalachian Basin, our dedications include the most attractive acreage operated by resilient producers that continue to demonstrate their ability to continuously improve on their cost structures. You can see this playing out as our Northeast gathering volumes grew faster than the total Northeast supply. So overall, if you looked at the information from point logic, you would see that the Northeast wellhead natural gas production for all of the area, even including outside of Williams, was up by 2.2% on a 3Q 2020 to 3Q 2019 comparison. And ours, as we've shown, was up by 8.4% in gathered volume. So we really are not only in the right basin, but we're also in the right parts of the basin in the Appalachian area. We expect this trend to continue in response to very favorable forward strip pricing for 2021 and a very well-positioned group of customers in both the Marcellus and the Utica. We'll talk more about our G&P business when we get to our investor focus area segment. But for now, let me turn it over to John to highlight our Q3 results.

Thanks, Alan. We're going to go to slide 2 here. And once again, we're very pleased with our results this quarter. And as an overall theme, our cost reduction efforts, our new Transco projects brought into service and our incredibly strong results out of our Northeast gathering and processing segment helped to offset some challenging conditions in the deepwater Gulf of Mexico from heightened hurricane activity. You can see the strong performance in our statistics. First, looking at adjusted EBITDA for the quarter, it was down $7 million or 1%. However, this is very misleading, given that we expected and realized a $33 million step down in deferred revenue at our Gulfstar deepwater platform this quarter. In addition, the third quarter of last year included $28 million of incremental EBITDA from the Transco rate case settlement true-up for periods prior to the third quarter of 2019. So if you adjust for these items, our EBITDA was actually up 4% versus the third quarter of 2019, which is more indicative of the very strong quarter we had. And the same thing is playing out in our year-to-date results; our adjusted EBITDA is up 1%. But adjusting for deferred revenue step-downs and other noncash items, our year-to-date adjusted EBITDA is actually up similarly at 4%. We'll discuss EBITDA in more depth in a moment. Our adjusted earnings per share for the quarter increased largely due to lower depreciation. But again, just like adjusted EBITDA, would have been up much more strongly, had it not been for the noncash items I just mentioned. Distributable cash flow was down for the quarter due to increased dividends and distributions to our non-controlling interest owners, primarily related to our new Northeast JV, which is consolidated in our operating results and probably more so due to the timing of maintenance CapEx, which was higher for the quarter but down on a year-to-date basis. Our distributable cash flow year-to-date is down slightly, but the 2019 period included an $85 million cash tax refund that we've not benefited from this year. Without that cash tax refund, DCF is also up. As we look towards the end of the year, we still see distributable cash flow performance coming in above the midpoint of our guidance and likely above last year's results. On the capital spending front, our intentional capital discipline continues to drive capital spending down and free cash flow up. And to that point, capital spending for the quarter and year-to-date is about one-half of what it was last year. Of that, maintenance capital year-to-date is about $70 million less, and expansion capital spending is over $900 million less. With expansion capital spending expected to come in the $1 billion to $1.2 billion range for the year, and frankly, it's likely going to come in towards the low end of that range. And looking at our EBITDA and DCF forecast, we still predict that we'll produce excess free cash flow for this year above all dividends and all capital expenditures. This strong cash generation and capital discipline has helped us move towards our goal of improving our leverage metrics. And this quarter, our debt to last 12 months EBITDA is at 4.42 times, but we expect to end the year with that leverage metric being inside our guided goal of 4.4 times. And we expect continued improvement on the leverage metric next year, moving towards our goal of 4.2 times. Now going to slide 3, and looking at adjusted EBITDA for the quarter, let's dig a little deeper into that. Again, Williams performed very well this quarter despite an unusually active hurricane season that negatively impacted our Gulf of Mexico operations. As you'll hear throughout each segment, cost control has been a big benefit this year even after realizing higher bonus accruals this quarter in recognition of our strong performance. As I mentioned a moment ago, before we dive into each segment, we believe it's important to isolate a few unusual things to make the numbers more comparable and reflective of our ongoing performance of the business. We've identified those unusual items on this slide, which are shown on this chart as noncash comparability items, and they total $60 million. They consist primarily of two things. The first is the $33 million reduction in noncash deferred revenue step-downs in our transmission and Gulf of Mexico segment on our Gulf East franchise area. As a reminder, on deferred revenue, we received significant upfront cash payments several years ago from a producer, but did not recognize revenue at that time. We have been amortizing those payments we previously received into income over the last several years, and that amortization has been shrinking. The second item I'd point to is the $28 million rate case true-up entry made in the third quarter of 2019 that I described earlier. So, if you adjust for those items, again, EBITDA was actually up over 4%. So, looking at our segments, the Transmission & Gulf of Mexico assets without these non-cash items produced results that were $3 million better than the same period last year. New transmission pipeline projects added $14 million in revenues for the quarter, including the Hillabee Phase two project, that came into service in the second quarter of this year and the Gateway project that came on into service in the fourth quarter of last year. While we did see lower operating costs during the quarter, they were offset somewhat by increased bonus accruals and higher reinsurance and property taxes. Offsetting the positive revenues was about $15 million of lower Gulf of Mexico profits due to shut-ins, resulting from the heightened hurricane activity. The impact of the shut-ins can be further seen in reduced deepwater gathering volumes, which were down about 15%. Now going to the Northeast G&P segment, it continues to come on strong, producing record results and contributing $53 million of additional EBITDA this quarter. Collectively, total Northeast gathering volumes grew 8% in the quarter, and processing volumes were up 17%. These higher volumes drove revenue growth. And of course, we are realizing more revenue per gathered Mcf due to additional revenues earned from processing, transportation and fractionation of that gas and NGLs on the backs of some investments we've made over the last several years in this infrastructure. Equity method investment also drove EBITDA, where we benefited from higher record volumes, due to gathering expansion on that system in late 2019; the Marcellus South system, where we benefited from several new wells coming online over the last year; and to a lesser extent, higher volumes on Laurel Mountain Midstream. Finally, the Northeast also benefited from cost reduction efforts, much of which began last year, as well as from favorable maintenance expense savings. As a final note, adjusted EBITDA per gathered Mcf for our Northeast operating assets, when you include the proportional volumes from our non-operated assets, averaged $0.52 per Mcf in the third quarter of this year, compared to $0.49 per Mcf the same time last year, which is a 6% increase. Now looking at the West, that segment was flat to last year. Overall, revenues in the West were down slightly versus the third quarter of last year, but those decreases were offset by higher commodity margins and reduced expenses. Revenues declined due to lower gathered volumes, which were down about 7%, and were spread amongst many basins, with the biggest impact coming in the Haynesville, Wamsutter and Piceance. Of course, in two of these three basins, we have a customer dealing with bankruptcies and would expect to increase volumes as those producers move out of their bankruptcy. The volume decline, however, was muted somewhat by higher revenues in the Eagle Ford, where we agreed to a new contract with a higher rate than an MVC in December of last year. And just as with our other segments, the West experienced lower cost, again, as we keep a relentless focus on efficiency and cost control. Now going to slide 4 and looking at our year-to-date results. They showed growth of 1% in adjusted EBITDA, again, driven by many of the same factors affecting the third quarter growth. The Barnett and Gulfstar noncash deferred revenue step-downs totaled $85 million, while the net impact of commodity price fluctuations on our inventory linefill position created a $9 million noncash reduction in EBITDA this year. So without those noncash comparability items, year-to-date, adjusted EBITDA was up similarly to the quarter and it was up 4%. Again, looking at segments, our Transmission & Gulf of Mexico segment without those noncash items is delivering $16 million in growth, with an uplift from expansion projects and expense reductions being offset somewhat by lower Gulf of Mexico volumes and the impact that it's had on commodity margins. In the Gulf of Mexico, the total impact of shut-ins from COVID, hurricanes and the price collapse earlier this year has been $38 million. The Northeast is a huge part of our growth this year, adding $165 million in additional EBITDA over last year, with overall volumes up 7% and incremental revenues being realized from processing, transportation and fractionation of gas and NGLs, while at the same time, we've been reducing costs. And finally, the West is off by about $46 million versus last year, largely because of the Barnett, MVC cash payments that ended last year and the four points cost of service true-up payment that we received last year. Otherwise, in the West, gathered volumes were down about 3%, but were offset largely by reduced costs and increased revenues in the Eagle Ford due to the renegotiated contract in December of last year. Again, all in all, despite a tough market and a tough hurricane season, we've had a really good year on the back of cost reductions, Northeast performance and new pipeline projects coming into service on Transco. I'll now turn the call back over to Alan to discuss some of the key investor focus areas. Alan?

Great. Well, thanks, John, and just starting here again on Slide 5. We have a listing of what we believe are key areas of focus for our investors. And so first, I'll discuss our expectations for the 2021 financial performance. We expect to provide our 2021 financial guidance during our 4Q earnings release in February but we offer the following insights to what we expect for 2021 as follows. First, continued production of reliable and highly predictable cash flow with modest growth and improving returns; second, we expect to again generate discretionary free cash flow comfortably covering both our dividend and our growth CapEx; and third, we expect our adjusted EBITDA to continue showing growth driven by the following: first of all, gas supply demand setup favoring our various strong positions on gas. And so again, we would just tell you that gas demand will be driving our business. And the forward market certainly is driving many of our customers to make plans for growth across a lot of our systems and transmission projects like Southeastern Trail, early in-service of Leidy South as well. And then finally, we're no longer dealing with the downward pressure due to the non-cash deferred revenue step-downs that you just heard John talk about, and we don't expect to have the degree of deepwater shut-ins that we experienced this year from a number of different issues. So lots of nice growth drivers that are very predictable at this point. And we feel very confident about how those will shape up for 2021 at this point. We really expect only a couple of small items that will work to partially offset these growth drivers. First, we expect a small amount of overall cost increases that are really driven by both gathering volume growth and transmission capacity expansions that we've spoken to. But thanks to our operating team's continuous improvement mindset, we do expect our operating margins to expand again for the fifth consecutive year in 2021. And so again, our revenues are going to be outpacing any expansion in expenses. So really tremendous efforts by our teams continuing to focus on the operating margin ratio across our businesses. We also expect modest declines in the West segment from lower short-term NGL services that we enjoyed this last year. So we did have some opportunistic revenues in our NGL services business that we don't expect to enjoy again next year and weaker NGL margins from higher gas prices next year, of course, with those higher gas prices working against our keep-whole margins. On the capital allocation thoughts. First, our dividend is a key source of value for our investors, and we believe the reliability and predictability of our dividend is key to achieving appropriate valuation relative to other growth in income stocks. But beyond our dividend and planned growth CapEx, we will have discretionary free cash flow to allocate. One of the highest priorities for 2021, of course, will be to complete our deleveraging plan. And I'm proud to say we are on target to reach our 4.2 debt-to-EBITDA towards the goal that we've talked about a lot towards the end of 2021. And this should drive the BBB flat ratings across all three agencies that we've been seeking. Obviously, we think the strong balance sheet and higher credit ratings will continue to bring contraction in our yield, driving stock price appreciation for our investors as we continue to attract value investors outside of the energy sector. Once we reach our leverage target, we will have a variety of options to consider, which the Board will weigh with a focus on generating long-term sustainable value for investors. And of course, you all know these various options. Of course, one would be additional delevering. Another would be stock buyback, if our valuation doesn't improve from where we are today, and incremental investments in our regulated pipeline expansions and rate base. And so plenty of alternatives, plenty of things to utilize those free cash flows to drive additional value for investors. And now turning to look at our longer-term growth outlook. First of all, in the gathering and processing business, the nice growth that we've seen in our volumes versus the broad market is evidence of the strong position across our G&P footprint. You can see on Slide 9 in our appendix slide that the total wellhead production of natural gas is down slightly for 2020 on a year-to-date basis. So that's just looking across all of the domestic gas supplies, while Williams gathered volumes have grown by over 3%. And even in the face of the Gulf of Mexico disruptions that we're exposed to. There really isn't another public company with a comparable gathering and processing footprint. Our business is resilient and produces reliable cash flow, because of our focus on low-cost gas basins, our contracting practices, the wellhead connectivity that we have, and the very broad portfolio of gathering systems that we operate. Single-basin businesses or those with a single customer, or a small number of dominant customers are just not the appropriate comps for our G&P portfolio. Our more diverse asset base is driven by demand for low-cost natural gas, as we've spoken to many times. So, let's look at this driver for a moment. First of all, domestic demand and exports has been resilient this year, down less than 0.5% on a year-to-date basis. And you certainly wouldn't know it from the news, but the biggest single contributor to this decline was a nearly 14% decline in heating degree days from January through March of this year, which was a key driver of the res-com demand weakness this year, not the COVID-19 pandemic. In fact, if 2020's winter weather looked like 2019's January through March weather, the total Lower 48 total gas demand would be up, by 2% year-to-date. Exports, both LNG and pipeline exports to Mexico, were up this year, even after dealing with a very warm winter in Europe, resulting in a summer of low LNG exports. And we're now, as you are well aware, are now seeing LNG flows rebounding near the highs that we saw earlier in the year. As we've said before, demand is truly the key to our business. And this demand picture is driving the price response we are seeing. Continued price increases could eat into demand growth. So you should certainly watch closely for how producers respond to these price signals. However, we have confidence that producers see this as an attractive market. And we'll be able to respond very effectively to the increasing call on gas supplies, particularly in the very best of the Marcellus, Utica and Haynesville Shales, of which we are so fortunate to serve. Looking at the deepwater Gulf of Mexico, the competitive advantages of our existing footprint and unique operating expertise is bringing new business to our existing capacity. And we have been fortunate to contract for some very large and exciting new developments. These really begin ramping up as early as 2022, for the Taggart prospect, and this growth will continue for several more years as the more impactful opportunities like Ballymore come online. And as we have mentioned in the past, the capital required for this next tranche of large projects is very low, relative to the EBITDA growth. And so, we're really excited to see the kind of incremental returns that we're going to see, and the growth we're going to see in the deepwater Gulf of Mexico. And of course, our natural gas transmission systems remain advantaged versus competitors, with a lot of signals for growth in this area as well. The Brownfield nature of the expansions that we have causes less environmental impact. And thus, lower regulatory risk. Capital cost risk is also lower, when expanding across our existing footprint. And because of this, and the great work by our project execution teams, we see projects on or ahead of schedule. So let me just walk through a few of these. This is really impressive work, by our project execution teams. First of all, Southeastern Trail now has 150 million a day of its total 296 million a day of incremental Transco capacity placed into service, as of November 1. So, this kind of maybe slipped up on people, but we've been working towards an early in-service. And in addition to that, we have 80 million a day possibly in-service by year-end. So 230 million of our 296 million a day will be placed in service by year-end, well ahead of what we had expected. The final 66 million a day will be placed in-service, during Q1 of 2021. So, great work there. On an even more impressive schedule, due to customer demand and great work by our teams on the Leidy South Project, we have 125 million a day of the Leidy South, 582 million a day of total capacity that we expect to be online in the next month. So a full year ahead of the original project expectations and of course, this is important because this also provides additional gathering capacity out of our Northeast PA area. The integration of our customer relationships across the gathering and transmission businesses allowed us to recognize and then meet accelerated customer needs, providing unexpected value for both Williams and the customer. Even as we look forward on additional projects that are not yet in execution mode, Regional Energy Access is a project that is going very well on both the commercial and regulatory front and we have 100% survey permission that we've achieved. Obviously, this is a very critical milestone for the regulatory process today and we do expect to file for a FERC application here in the next three months. So, great work going on there as well. That will be another project that will expand capacity out of the Northeast PA area. Expectations of sustained demand growth are truly the driver of our transmission business and we've said before, our expansions are underwritten by 15 years or longer take-or-pay contracts and as you can see, this continues to show the confidence that our customers have in the long-term need for gas and gas transmission to serve growing gas demand and so we really are continuing to see a lot of great expansion opportunities along the Transco system that will be fairly sizable and continue to drive growth on that business for years to come. On the sustainability front, in August, we became the first U.S. midstream company to issue a climate commitment. We announced a near-term goal of a 56% absolute reduction from our 2005 levels in company-wide greenhouse gas emissions, and we would achieve that by 2030, putting the company on a positive trajectory to be net zero carbon emissions by 2050. We will continue to invest in environmental stewardship and reduce our carbon footprint while meeting the clean energy needs of our communities and delivering long-term value to our stakeholders. Our transmission networks are extremely well-positioned to aggregate and bring scale to multiple emission reduction opportunities, including taking out higher carbon fuels, and other near-term efforts while focused on exploring renewable energy opportunities, including renewable natural gas and solar energy. And we've established an internal team to explore and manage emerging opportunities like renewable natural gas, further deployment of solar across our systems, hydrogen and carbon capture across our entire footprint. But to be clear, these opportunities will compete alongside all other investment opportunities in our capital allocation process. So, we are proud to lead the midstream space in meeting the growing demand for American-made energy while outlining clear steps towards a clean energy future. We hope to challenge others to establish similar goals based on what we can reduce right here, right now. So in closing, I'll reiterate that we've intentionally built a business that is steady and predictable. Our natural-gas-focused strategy positions us well to capitalize on continued natural gas growth, our existing transmission infrastructure offers growth advantage, and our low-cost basins that we serve provide predictable cash flow and position us to grow in a wide range of supply and demand scenarios. Second, of course, today is Election Day. And there has been a lot of debate during this political cycle about the future of our industry. I'll just say that at Williams, we remain bullish on natural gas because we recognize the critical role it plays and will continue to play in our country's and our world's pursuit of a clean energy future, irrespective of the political backdrop. Thanks to natural gas, the U.S. continues to see significant reductions in CO2 emissions, lower consumers' utility bills, and enhanced opportunities for investments in renewable energy. And then finally, as we continue to navigate the COVID-19 pandemic, I want to once again recognize the tremendous efforts of our entire workforce in ensuring the delivery of natural gas to America's cities and communities. Often, I think we take for granted the great reliability that's provided by the great operating companies of our nation and ours is no exception in terms of the reliable service that we provide for our industry. And I'm extremely proud of our employees for their efforts to keep our operations running smoothly while also going the extra mile to keep themselves and their coworkers healthy. And with that, I'll open it up for your questions.

Thank you. Our first question comes from Jeremy Tonet from JPMorgan. Please go ahead. Your line is open.

Hello. Good morning.

Good morning, Jeremy.

I just want to start off on capital allocation. I know you touched on it a bit in your prepared remarks there. But just wondering if you had any more clarity on where 2021 CapEx might land given how project timing could potentially move around a bit and how this level of CapEx could approach — could impact your approach to deleveraging and any potential buybacks. Trying to get a feel for how that interplays within 2021 itself.

Yes. Great question, Jeremy. Obviously, we haven't laid out that guidance firmly yet, but we do have a pretty good idea. I think one of the things that's helping on that end is these projects are being finished earlier than we expected. So that's a real positive. And obviously, because our capital has come down this year, a lot of that is cost reduction as well. So I would just say, we are seeing really positive signs on the cost as we've gone out for bid. The construction market is a little bit slow right now. And as a result of that, the bids that we've been seeing coming in for our projects are coming in below our budget. So I would say a little too early to call that. But right now, I think we're feeling pretty good about being able to manage to a capital budget that is somewhere in the same range as what we saw this year. So I don't know, Michael, if you have anything to add to that on the capital.

I would just say, and I will talk about in the opening remarks, we will cover all of our capital and dividend next year and be free cash flow positive in regard to our overall company performance. As Alan said, we're seeing great bids from our contractors. Our teams are doing an incredible job executing our projects and achieving under-budget performance on all of our major projects this year. And we have high expectations to continue that next year with where the market is in regard to construction activity.

That's very helpful. And I know you have a number of comments you provided on renewable energy there. And you talked about RNG interconnections and solar installations. Just trying to dig in a little bit more there, if you could expand on how big the CapEx dollar opportunity set for you could be on the renewables front, I figure it's bigger than a bread basket, but trying to figure out how big that is.

Yes. Let me have Chad Zamarin, who is leading that — sorry, that emerging opportunities group. Chad?

Yes. Thanks, Jeremy. And in that space, it's still early days, but I think we announced today that we've just connected our sixth RNG project. We see a pretty good pipeline of opportunities in that space. I'd say in the near term, still modest capital investment over the next couple of years, probably less than $100 million in RNG projects. On the solar front, we have approved 12 projects that have advanced through what we would call our Gate One capital allocation process. Those projects aren't yet to full investment decision, but those projects constitute around $200 million to $300 million of investment in solar installations. And so those projects will continue to move through our process over the next several months. And I would just say, we spent a lot of time building up talent and capabilities. And I think we view ourselves as an energy infrastructure company. And we are very focused on, as you can also see, being a part of the clean energy solutions for our country and for the rest of the world. And we see natural gas as really the most impactful energy source in that regard. But we're very committed to making sure our infrastructure and capabilities are part of any solution with respect to the future of clean energy. So we've also stood up a team that is now focused on hydrogen and other carbon capture technologies. But I'd say that's very early days, and will probably not be a lot of capital investment in the very near term, but we'll continue to look to be a part of the solution in those areas as well.

Got it. That's very helpful. I’ll stop there. Thanks.

Thank you. And our next question comes from Praneeth Satish from Wells Fargo. Your line is open.

Thanks. Good morning. Your partner on Overland Pass sold or plan to move their volumes onto their wholly owned pipeline. Just wondering if you would still get paid if they move volumes. And then if not, what's kind of the plan there to try and backfill those volumes.

Good morning. This is Michael. I'll take that. In regard to our partner on Overland Pass Pipeline, we've anticipated the movement of those volumes for some time now with their construction of their pipeline from the Bakken. And they've taken the volumes, but continue to pay us this year in partnership with our agreement that we've had in place with them. And so this has been an expectation that we've had. We've built this into our plans for next year, but we've also got our Rocky Mountain Midstream entity in Colorado that we do anticipate having additional volumes coming from that entity. And that's where we've anticipated those volumes coming in and backfilling some of the volumes that are leaving us from our partner on the OPPL pipeline.

Okay. Great. And then just on the renewables front, I think, so far, most of — or all of your investments tied to RNG have consisted of building out laterals. What's the appetite to maybe push further upstream and invest in the actual facilities and landfills or dairy farms that capture and process the methane?

Yes. I would just say we're going to invest where we think we have the biggest competitive advantage and can generate the highest returns. And some of those projects that are backed by quite a few tax credits and subsidies generally have quite a bit of financing and fairly low returns on them. So we're going to focus on the part of those investments where we can make a return that competes within our capital allocation framework. As I'm sure everyone is aware, the investment and the returns in that space have narrowed considerably with all the popularity around that. So we're going to stick to the areas where we have really strong competitive advantage to create better returns.

Yes. And I would just add, our footprint does point us towards areas of opportunities. I would just say, an RNG project, a lot of the infrastructure required for bringing RNG to market is the kind of infrastructure that we're very familiar with. It's primarily trading and processing of natural gas and gas by-products. It's relatively small scale. But again, I think to Alan's point, we're very capable of investing further upstream into those facilities but we're going to make sure we focus on where those returns would be most attractive.

The last thing I'd say is, we remain a noncash taxpayer at least through 2024 in our projections. And so therefore, tax credits, it's tough for us to make value of that. So we've got to find partners to co-invest and take advantage of those tax credits in many cases. So some of the things that make the returns more attractive upstream really aren't as valuable to us.

That’s helpful. I will stop there. Thanks.

Our next question comes from Shneur Gershuni from UBS.

Hi good morning everyone and Alan congrats on the new role. Just to start off here a little bit here. You sort of intimated in your prepared remarks that you expect EBITDA to be higher next year versus this year. I was wondering if you can walk us through the pluses and minuses directionally yet. Obviously, without giving a specific number as to the support of that view, are you seeing some more activity potentially in the Haynesville? Is that offsetting the earlier question about the Overland Pass volume loss? Just wondering if you can just sort of give us the ledger of pluses and minuses as to, directionally, what underpins the expectations for EBITDA to be higher next year versus this year?

Yes. Sure, Shneur. And I'll just kind of go back through the notes that I laid out there. First of all, as I mentioned, the gas supply and demand situation is turning out to be a very favorable position for gas-focused basins. Obviously, with associated gas continuing decline and demand hanging in there and starting to grow again. We really feel good about the way we're positioned within our gathering and processing basins. Obviously, those lower-cost basins are best positioned for that. But if you really look at how that's going to get balanced, it's hard for the market to balance itself without drawing on the basins that we serve, and serve in — with some concentration. Secondly, the transmission projects like Southeastern Trail and early in-service for Leidy South will drive growth as well in 2021. And then, of course, one of the things that we normally have had some downward pressure like we overcame this year from some of the non-cash items, that John talked about, and so we're not having to overcome some of those headwinds this year. And then finally, of course, the $38 million impact in deepwater Gulf of Mexico this year, won't be there. And we've had a number of tie-ins this year in the Gulf of Mexico that will produce higher revenues next year. So, those are some of the primary drivers, but I would just say, we're feeling really good about the way we're seeing volumes in the Northeast right now. And if we didn't see anything, but volumes stay flat from where they are here in the fourth quarter through 2021, we would see a really nice growth in terms of our earnings and EBITDA in the Northeast. So hard to say that we won't see some growth somewhere, because somehow the market is going to have to balance itself, and we certainly are seeing a lot of producers making plans for that. But we're — it's really early to call a whole lot of growth there, and we have pretty modest growth built in. But very modest growth while keeping our costs relatively flat is pretty powerful for us and our EBITDA growth. So I mean I don't want to get people out ahead of where we are. I certainly mentioned that our growth would be modest. But I would just say, there's just a number of things that give us quite a bit of confidence and not really anything all that exciting happening across our business to drive growth next year.

So that makes perfect sense and really do appreciate that color. And maybe as a follow-up question, in the prepared remarks, you sort of talked about being free cash flow positive after dividends next year. Buybacks is one of the arrows in the quiver, and it's certainly becoming a — all the ranges of late with everybody announcing authorizations. Just wondering, is — how is the Board thinking about approaching it? Do you have to actually hit the leverage target or exceed the target before you authorize and start buying back stock, or given that you're already on a trajectory, you're close, that it's something that you can start sprinkling in sooner than actually hitting the target? Just kind of wondering your thoughts around the topic?

Yeah. No, I would just say that this is a very deliberate and disciplined Board, and we've been very clear about this goal. And I don't think there's anything that I can foresee right now anyway that would waiver. Obviously, if we saw a stock price collapse or something like that, that might change that mind and be opportunistic. But I would just say, we've been pretty clear, pretty disciplined. And I see us continuing to push forward on that goal as a top priority. So I really don't see much. And if we did do buybacks, it would be a sprinkling in. And while it might be popular, I would just tell you that we're going to focus on what we think fundamental value is. And right now, we think that fundamental value is getting our debt down to those targets and gaining the credit rating across all three agencies.

Perfect. Thank you very much, and that does it for me, guys.

Thank you. And next question comes from Jean Ann Salisbury from Bernstein. Your line is open.

Good morning. In an aggressive renewables adoption scenario where utilities' gas demand goes down dramatically, but utilities still need gas availability to meet peak demand, how would you see contract structures on gas pipelines changing, if at all? And are there currently examples on your pipelines of very high MVCs compared to usage and did they require different types of contracts?

Jean Ann, I would just say we haven't seen anything resembling that at all in our markets. The capacity that we have is highly valued. And the last time we had any capacity come up available that got turned back, the only thing that we could distinguish the bid on was on term and that — and this was last year. And the term was 84 years, was a successful bid on that. So we're not really seeing any need to discount or would see a need to provide any discount in our markets, because our rates are so low compared to what the avoided cost or the alternatives are. So we really don't see pricing pressure in our markets. We're always working with our customers to provide the very best service. But I think from a pricing standpoint, there's just not any pressure on the pricing within our — I mean, I always say that's the good news and the bad news about our regulated pipeline. The bad news is the rate's capped. And the rate, we can't expand that rate. But the good news is, that's really hard to compete with in those markets. And so, really don't see it. But I would just tell you, we're not — despite the talk on this issue, we are not seeing the utilization come down on our system on the gas-fired generation, despite a lot of renewables being interjected into the market. And of course, as long as we still have the high degree of coal-fired generation in a lot of our markets, we're going to continue to see expansions of capacity demand for our services. Michael, I don't know if you'd add anything to that.

No, I think you were right on there, Alan. I would say that, based on the demand that we're continuing to see on the Transco and other transmission pipelines we have, we don't anticipate having to negotiate any kind of peaking agreements. Now if there's an opportunity to provide a peaking service that we can charge a rate for, that is desirable for us, then we'll absolutely pursue that. But at this point in time, our customers are continuing to see demand for long-term year-round contracts, and that's what we'll continue to pursue.

I think an interesting derivation of that question is, when are the utilities going to start charging the independent renewables developers a backup charge for the power that they're backing up, the interruptible power coming from the renewables resource. And that's not happening today.

Yes. No, that's really helpful. And then kind of 10-plus years from now, your answer is so extremely helpful and valid. Thank you. And then is it possible to separate out how much of this year's growth CapEx went to well connects, even just roughly?

Well, I can tell you, in total, from a capital spending standpoint, the Northeast total capital spend for this year is probably going to be a little bit south of $300 million. In the West, it's less than $100 million. So when you — and that's a combination of maintenance and expansion capital spending. And embedded within that is some processing work. So I don't want to say that's all well connect capital, but it's fairly insignificant now.

Great. John, that’s helpful. Thank you so much.

Jean Ann, it's got to be — that's got to be a pretty difficult thing in areas like the Northeast PA, where we're building big pipelines into these well pads and so you might call that a well connect, but it's a 20-inch pipeline a lot of times, sometimes even larger. Because the producers are effectively — by drilling these laterals out of these single locations, they effectively are providing what used to be a well connect by bringing that all into one location there for us. And so what we see actually — rather than us having to go connect those individual wells, we're seeing the producers just continue to drill out those pads over time and keep the volumes full on those fairly large lines that we've built to them. So it's gotten really fuzzy, particularly in the Northeast with these very large volume pads. It's gotten pretty fuzzy to think about something being a well connect. A lot of these pads are delivering more gas than a single gathering system does in a lot of parts of the country. So it's really gotten kind of fuzzy on that front. But well connects in the West are probably a place that's a little easier to keep track of in that regard. And as John mentioned, we spent less than $100 million this year in the West.

Thank you. And our next question comes from Christine Cho from Barclays. Your line is open.

Good morning. Maybe, if I can ask the 2021 CapEx question a little differently. And I understand this can change in the next couple of months, but I can think of well connects or Northeast and Haynesville, maybe a project on Transco materializing from the cancellation of ACP, some small residual spending on Leidy South and Southeastern Trail and maybe some additional Gulf of Mexico tiebacks. Would you say those are the main pieces of the CapEx program next year as it stands right now?

The only thing I might add to that, Christine, is the one thing that is notably missing from your list there would be the build-out for the deepwater Gulf of Mexico project. And so that's a pretty sizable project. And so that's probably — and remember, that is reimbursable if they were to cancel that for some reason, but that's getting pretty far along for anybody to think about canceling at this point. So Michael, I don't know if...

Yes. I mean, that was the one that was sticking out for me. We ordered the pipe for that project based on the reimbursable agreement that we have with the producer customers there, and that's a pretty substantial order, in order for us to get that pipe on time for the project. And Regional Energy Access will be another one that will ramp up next year as well as, obviously, the Leidy South construction, which we have full notice to proceed now on Leidy South for our restoration construction and so those are underway. That's the gating item on that project, and we'll start construction on our pipelines for Leidy South in January. That's a pretty small component of that project with some Brownfield moves there. The compressor stations are really the bulk of the work there on Leidy South.

And maybe just one other thing, and it's not sizable, but we may need to do a little bit of processing work in the Northeast expansion as we're filling the systems up.

Got it.

A point as well, we've — our Oak Grove processing complex, we actually stopped construction on TXP3 there and we've ramped that back up now. So we had a lull there of about six or eight months where we had idled that construction work. And now we're above capacity there on the processing complex, and we've accelerated that work now, and we anticipate that third train at Oak Grove being online sometime in the first quarter of '21.

Got it. And just a clarification on the Regional Energy Access. I don't think that project came online until like '23. So is there really going to be that much spending on that next year?

Well, there won't be Christine. You're right. That's a 2023 in-service, but it is another component of our Transco expansion opportunities, and it will initiate some uptick in spending next year as well as, obviously, the Leidy South construction, which we have full notice to proceed now on Leidy South for our restoration construction and so those are underway. That's the gating item on that project, and we'll start construction on our pipelines for Leidy South in January. That's the gating item on that project, and we'll start construction on our pipelines for Leidy South in January. It won't accelerate really until 2022 and 2023.

Got it. And then as a follow-up, Alan, you mentioned the different ways to drive additional value, and you mentioned debt pay down, stock buybacks and investing in projects. Assuming you get to the 4.2 times leverage and are comfortably in BBB flat territory, what return thresholds would any transfer of projects need to clear in order for it to be a better use of capital than buybacks at this juncture?

Yes. That's a good question. I think, obviously, that's going to determine how we see the stock market and how much value we think there is to investor for additional debt reduction. Obviously, that's something that there's not a bright line on and we'll have to use our own best judgment around how much value we think there would be to the shareholder through further debt reduction. So that's the answer to that part of the question. And then the second piece is what stock price is going to be at that point in time, and that will set effectively what the return threshold would have to be for those incremental projects. And I just tell you, there's all kinds of places that make good and very profitable rate-based investment on the Transco systems in terms of modernization of the systems and emission reduction opportunities. And it really is just going to depend how those returns look. And obviously, we've been in the process of negotiating what that would look like in terms of emission reduction projects. And until we know what that return would be and we know what the value, we would assess at that point in time, the debt reduction and stock price that will determine that. But there's really — the good news is we don't have to predetermine that. We'll see what the markets look like when we get to that point at the end of '21. And I'm very confident in our Board's ability to make a great decision for the benefit of the shareholder when we get to that point.

Fair enough. Thank you.

Thank you. And our next question comes from Gabe Moreen from Mizuho. Please go ahead. Your line is open.

Hey, guys. I had a two-pronged question on the Northeast. There's been some customer consolidation, I think, in Appalachia. Wondering if there's any impacts or opportunities from that. And then also, assuming the forward curve holds or does even better from here, would there be any significant CapEx increases if your customers decide to go beyond, let's call it, maintenance to modest growth mode?

I would say, EQT coming in and buying into the assets in Appalachia that we are a partnership with Chevron on there is only a positive for us. EQT is a great operator. They're certainly getting their cost under control on their drilling and their completions and really doing an admirable job there. We have the opportunity to bring additional volumes in there with not a lot of capital deployment in regard to possibly EQT deploying more money there, be able to drill. So I think that's just a great opportunity and upside for us there with Laurel Mountain Midstream. They'll be a partner with us on the midstream assets there with that acquisition, owning 31% of that entity with us. And so we're looking forward to working that relationship that we've already built with them even more so.

Great. And then as a follow-up, clearly, there's been a lot of consolidation on the upstream side of things. In the past, you talked about asset sales, done a lot of portfolio shaping yourself. Those discussions still ongoing? Do you think those perhaps happen in 2021? Just curious for your thoughts there?

Yes, that's a good question. We're certainly — we'll continue to pursue that. I think we do believe that the cash flows that our West G&P asset and the free cash flow, the tremendous amount of free cash flow they generate is very valuable. And we think the predictability that we've seen this year, along with the way that we've been able to manage through the bankruptcy concerns around these assets, we think that really is going to position this well for having them better valued in 2021. And what exactly path that takes is TBD. But we certainly are continuing to look for opportunities to make sure that those are more fairly valued within our stock price, one way or the other. So yes, we're still working on it. And I think some of the clouds that existed over that are certainly lifting pretty rapidly, with the way some of the concerns — particularly around the Chesapeake bankruptcy and the way those concerns have really eroded as we haven't been listed as any rejection and very confident in our ability to preserve the value in our contracts there.

Great. Thanks, Alan.

Thank you. And our next question comes from Alex Kania from Wolfe Research. Your line is open.

Thanks. Just a question, maybe to put it a bad pun about the elephant in the room, I guess, the — talk from today. But just are there any elections or statewide races that you're particularly focused on, or any kind of latest comments or thoughts you might have just in terms of maybe any shift in energy policy in the U.S. based on a Biden or kind of a Trump reelection?

Yes. As I mentioned in my opening comments, I think we're — we feel like that natural gas in a sober, less-polarized moment is going to be a really important tool to continue to utilize renewables at a cost-effective manner and to continue to decarbonize energy use here in both the U.S. and around the world. And we think it's going to be a powerful tool. So the more serious we get about decarbonization, the better it is for our business. If the focus is just around eliminating fossil fuels, that's a different story. But if we really get serious about decarbonization, we think our business is extremely well-positioned in that environment. Secondly, I would say, on a more tactical level, I think probably one of the higher near-term probabilities, if there was a Biden administration win would be a corporate tax increase. And actually, that works out to be a positive for us within our regulated assets, because that would allow us to raise the rates back on certain pipelines that we had to lower when the corporate tax rate was lower. We do have a rider within those rates. And as well on Transco, we had to accept an impact to our rate case this last time around because of the lower corporate tax rate, and we would get those back. Now of course, we're not paying those cash taxes, but the way the rate case process actually works, we get to recover for whatever that corporate tax rate is. So in the near term, we would see — probably one of the few energy companies that would see kind of a near-term positive coming out of that. And longer-term, we think if we really are constructive and really get serious about going after decarbonization, we think we can play a very important role in that process.

Great. Thanks very much.

Cheryl, we got time for one more question. Cheryl?

And our next question comes from Travis Miller from Morningstar. Please go ahead. Your line is open.

Good morning. Thanks for taking my question. I was wondering, as a follow-up to the hydrogen conversation, what types of projects would you be looking at? And what's the timing on those specific projects? So not timing in terms of when you'd start, but once you started, how long would those projects take to go from first investment to in-service?

Travis, thank you very much for the question. I would just say, first of all, it is long-dated. So we're looking at a number of opportunities, but whatever we do, we're going to be looking to do it in a serious manner. And the scale that we can bring to hydrogen is probably second to none in terms of the utilization. And I think it's important to — when you think about hydrogen, to the degree that we're burning hydrogen in place of another carbon-based fuel, we do get emissions reduction. And that doesn't make any difference whether it's blended in with the natural gas or if it's separated, the emission reduction opportunity is exactly the same. And so our ability to blend in hydrogen into the existing systems is a really powerful tool here in accelerating the use of hydrogen to reduce carbon emissions. And so our ability to take excess renewable power in markets and both be able to help with the transmission of that energy and by converting the excess renewables power — which I think most people would agree that there's going to be a good chance that we're over-investing in renewables in certain pockets relative to the ability for that generated power to meet demand — there will be a need to transport that as well as a need to store that. If you think about the way our systems are set up, once you've converted that excess power generation into hydrogen, now we've got the existing systems in place, the ability to both transport and store that without incremental capital investment. And we think that's going to be really powerful as we emerge into that. Secondly, in markets where there is a big push on reducing emissions and accelerating the use of hydrogen, we're extremely well positioned with our systems in those areas as well to be able to help utilize hydrogen both as a technical tool and a political tool for permitting of our assets. And so we're really excited about the role we can play in that. And we can play it in a way that's not just a novelty and not just a pilot project, but one that truly gets us on the road towards utilizing hydrogen more broadly without waiting on long system development and long infrastructure developments in the market. So that's how we intend right now to go after it. And we'll certainly be looking for opportunities along those lines.

That's great. I appreciate that. And then, just a real quick follow-up to the capital allocation discussion. What's your thought around if the stock price stays here and the dividend yield stays up above 8% or so. What's your thought around foregoing perhaps a dividend increase and instead directing that capital back into some of the options you've talked about, stock buybacks or incremental investment? Just thinking about the dividend growth element of that situation.

I think, as we've mentioned before, we intend to keep our dividend growth in line with our cash flow growth. And we think the predictability and the reliability of continuing to do what we say we're going to do is valuable. And we certainly have the capabilities to do that. Ultimately, that's a Board decision in terms of that. But I would say from a policy standpoint in the company, we continue to expect to match that up with our cash flow growth and free cash flow growth. So it's a great question. I would just say that's a Board-level decision. But as we sit here today, we would expect to continue to grow it alongside the degree of cash flow growth that we've got in the business right now, which obviously is modest, and we've talked about that. So that's the expectation.

Okay, great. Appreciate that.

Cheryl, we're ready to wrap-up the call, please.

Thank you. That concludes our Q&A for today. I'll turn the call back to Alan Armstrong for closing remarks.

Thank you, Cheryl. Well, thanks, everybody, for joining us. We really are excited to be able to prove out the way our business is continuing to stand up with a lot of external headwinds, and looking forward to continuing to see these predictable cash flows continue to grow. And I really appreciate all the interest in the company, and the great questions today. So have a nice day. Thank you.

Thank you for joining us, ladies and gentlemen. This concludes our call, and you may now disconnect.