Williams Companies, Inc. (The)

Good day, everyone, and welcome to the Williams fourth quarter and full year 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 Giovanni, Vice President of Investor Relations. Please go ahead.

Thanks, Lindsay, 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 a 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 reconcile to generally accepted accounting principles. These reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

Great, and thanks, Danilo, and thank you all for joining us today. We're pleased to share the results of a very strong fourth quarter, rounding out a year of record business performance for Williams that yet again illustrates the stability and predictability of our business. So starting here with slide one. First of all, I'm thrilled to announce that our EBITDA once again exceeded the midpoint of our original guidance range for the fourth consecutive year and resulted in a 4% CAGR for this same four-year period. And that also, during the same period, we dramatically improved our credit metrics through our asset sale program. So really a nice, steady period here of very predictable growth and balance sheet improvements. This unmatched predictability is important to our value proposition and is further reinforced by this being the 20th consecutive quarter of meeting or exceeding street expectations. We also met or exceeded all of our other key financial metrics, allowing us to once again produce positive free cash flow, even after buying the outstanding interest in Cayman 2 that controls Blue Racer Midstream in the fourth quarter. Our focus on continuously improving our project execution, our operating margin ratio, reliability metrics, and safety performance delivered strong financial performance again in 2020 and allowed us to yet again achieve record gas gathering volumes and contracted gas transmission capacity. And all of these steady improvements and accomplishments build off of a clear foundational strategy that allows us to stay focused and aligned across the organization. We've demonstrated incredible business resiliency in a year of unprecedented challenges for our industry and our country. Our strong results in 2020 show just how durable this business can be against several headwinds, such as the COVID-19 pandemic, and associated oil price collapse, major customer bankruptcies, and an active hurricane season in the Gulf of Mexico that exceeded anything from an outage standpoint that we had on record. This tumultuous 2020 market environment allowed us to truly distinguish ourselves. In fact, we were one of the few midstream companies to maintain and, in fact, deliver on our pre-COVID guidance ranges that we provided to you in 2019. And I'm excited to see what this organization can produce without the large number of headwinds that we navigated through this past year in 2021. Moving on here, in addition to executing on our business in 2020, we accelerated our ESG performance. Last summer, Williams became the first U.S. midstream company to announce a climate commitment, setting an emissions reduction goal for 2030 that is based on real, achievable targets and that imposes accountability on the management team that's setting these goals. we believe that focusing on the right here and right now opportunity sets us on a positive trajectory to achieving net zero target by 2050. In addition, we co-led an industry effort to standardize ESG metrics with the Energy Infrastructure Council And in January, we hosted the industry's first ever ESG event, specifically devoted to sharing the company's direction, goals, aspirations, and tangible accomplishments related to ESG performance. In summary, In 2020, we once again demonstrated the stability and predictability of our business, and importantly, we've also shown the ability to focus and execute our plan without being distracted by the challenging macro backdrop. And with that, I'll turn it over to John to go through the details.

Thanks, Alan. As a very high-level summary for the quarter, our cost reduction efforts, new Transco projects brought into service, incredibly strong results out of our Northeast GNP segment, and a catch-up of minimum volume commitment, EBITDA, from a favorable WAMFetter Southland bankruptcy settlement, helped to offset a decline in profits from deferred revenue step-downs at our Gulfstar Deepwater platform, along with shut-ins from hurricane activities early during the fourth quarter of 2020. As you can see, the strong performance in our statistics on this page. In fact, we saw improvement in all of our key financial metrics, both for the fourth quarter and for the full year. First, our adjusted EBITDA for the quarter was up $52 million, or 4%, for all of the reasons I just mentioned. The same played out in our year-to-date results. Adjusted EBITDA year-to-date was up $90 million, or 2%. However, I think it's interesting to point out that if you adjust for non-cash to deferred revenue step-downs at our GulfStar platform and at our Barnett Gathering System, both of which were known and expected, as well as a few other smaller non-cash items, our year-to-date adjusted EBITDA without these non-cash comparability items is actually up 4%, again, much like it was during the fourth quarter. We'll discuss EBITDA variances in more depth in a moment. Adjusted EPS for the quarter increased 29%, largely due to increased EBITDA and reduced income taxes. During the fourth quarter of 2019, there was a larger-than-normal state tax adjustment and also, to a certain extent, lesser interest expense this year. Our year-to-date EPS is also up 11%, again, due to increased EBITDA, lower allocations of income to non-controlling interest owners, and again, to a lesser extent, due to lower interest expense. This quarter, we're presenting a new cash flow metric and will continue to present this going forward. The measure is available funds from operations. This measure will replace distributable cash flow. And it's similar to DCF, except it's derived from cash from operations and is before all capital spending, including before maintenance capital. Or said differently, AFFO is simply cash from operations, adjusting out working capital fluctuations, and also adjusting for cash flows from or to our non-controlling interest owners that shows up in the financing section of our cash flow statement. A reconciliation of this measure to cash from operations can be found in the appendix of this presentation and also in our analyst package. You can see the ASFO grew for both the fourth quarter and year to date, Similar to the growth in adjusted EBITDA, except some of the EBITDA growth is from our consolidated JVs, and so some of that growth does belong and does flow to our JV owners. Distribute cash flow increased for the quarter due to higher EBITDA and also due to a $42 million alternative minimum tax refund we received during the quarter that was not present in the 2019 period. DCF for the year is also up, again, due to higher EBITDA and lower maintenance capital offset somewhat by increased EBITDA paid to our non-controlling interest owners and due to lower alternative minimum tax cash refunds that we received for overall in 2020 versus 2019. On the capital spending front, our intentional capital discipline drove capital spending down this year and free cash flow up. And to that point, our total capital spending for the year was 40% less than last year, And our spending this year included the acquisition of most of the remaining interest in the Cayman 2 Blue Racer ownership for about $160 million in mid-November. As a result of that acquisition, we are now a 50% owner of Blue Racer with first reserve owning the other 50% interest. And we're excited to see what synergies we can bring to that business now that we have a larger stake and we're the operator. Included in this capital spending number is also maintenance capital, which for the year was $393 million, about $107 million less than it was in 2019. Finally, if you put our AFFO in 2020 of $3.6 billion up against our total capital spending, including maintenance, of $1.5 billion and our dividends of $1.9 billion, you can see that we were free cash flow positive in 2020. This strong cash generation and capital discipline has helped move us towards our goal to improve our leverage metrics for the year. And this year, our debt to EBITDA metrics ended at 4.35 times down from 4.39 times at the end of 2019. So 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 this quarter. As you'll hear throughout each segment, cost control has been a big benefit this year. Before we dive in each segment, we believe it's important to isolate a few unusual items to make the numbers more comparable and reflective of the ongoing performance of the business. We've identified those unusual items, which are shown on this chart, as non-cash comparability items. Interestingly, for the quarter, they net to only $2 million, and they consist primarily of two things. The first is a $24 million reduction in non-cash deferred revenue step-downs in our Transmission in Gulf of Mexico segment on our Deepwater Gold Star platform. As a reminder of deferred revenue, we received significant upfront cash payments several years ago from the deepwater producer, but did not recognize revenue at that time. We have been amortizing the payments we previously received in the income over the last several years, and that amortization has been shrinking. The second unusual item is a $20 million minimum volume commitment true-up entry that we made in the fourth quarter of 2020 related to our settlement with Southland who agreed to pay us the MVCs they owed us for the year. This adjustment is for the first through the third quarter that we recorded in the fourth quarter. We had stopped recording those MVCs at the beginning of 2020 when Southland originally filed for bankruptcy. So with or without those non-cash items, our EBITDA was up over 4%. Our transmission in Gulf of Mexico segment produced results that were $25 million better than the same period last year. New transmission pipeline projects added $17 million in revenues for the quarter, including the Gateway project that came into service in the fourth quarter of 2019, the Hillaby Phase II project that came into service in the second quarter of 2020, and the Southeastern Trails project that went into service during the fourth quarter of 2020. We also did have a little over $20 million in lower costs during the fourth quarter of 2020 due to lower maintenance and lower labor expenses. Offsetting these positives was $10 million in lower Gulf of Mexico profit due to shut-ins resulting from hurricane activity occurring in October, which is unusual for hurricane activity this late in the year. The impact of the shut-ins can be further seen in reduced deepwater gathering volumes, which were down about 13% quarter over quarter. The Northeast GMP segment continues to come on very strong, producing record results and contributing $29 million of additional EBITDA this quarter. Collectively, total Northeast gathering volumes grew 7% in the quarter, and processing volumes were up 9%. 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. As a result, our EBITDA from equity method investments improved by a little over $20 million in the Northeast, which also includes the additional benefit of additional profits from Blue Racer, again, due to our increased ownership, which again was acquired in mid-November. The Northeast also benefited from cost reduction efforts of about $9 million, much of which came from reduced labor costs. And then finally on the West, our West segment was down about $8 million compared to 2019. But within that, revenues overall improved a little less than $10 million in the West. with increases coming from higher rates and net MVCs in the Eagleford supply basin due to the contract renegotiations that we completed with Chesapeake in late 2019 and due to special payments received from our partner on OPPL for allowing them to pull volumes off of the system. These revenue increases were offset somewhat by lower deferred revenues in the Barnett Shale, lower Haynesville revenues due to lower volumes and rates, and slightly lower volumes in the Mid-Continent and Rockies. Despite revenues being up, in total, gathered volumes for the West were down 8%. Interestingly, though, roughly 90% of that volume decline occurred in the Hainesville, Eagleford, and Wompsetter. And of note, each of these basins were impacted by customer bankruptcy. And with the Southland reemergence filing a couple weeks ago, all those bankruptcies should be resolved soon. Also of note, in two of those three basins where we saw a majority of our volumes decline, specifically in the Wham Sutter and Eagleford, our revenues are protected by MVCs. So overall, the reduced volumes only had a small impact on revenues. And just as with our other segments, the West experienced lower costs at about $3 million as we keep a relentless focus on efficiencies and cost controls. Now, offsetting the higher revenues and lower costs in the West were commodity margins, which declined about $8 million due in part to lower volumes and due to a contract amendment there. We also had the absence of a favorable property tax reimbursement that we received in the fourth quarter of 2019. That was $6 million, and it was something that we had received from a third-party compression provider. And we also had lower JV EBITDA in the fourth quarter of 20 of about $4 million, with most of that coming from lower OPPL profits. And again, though, our partner on OPPL kept us whole, as I mentioned a minute ago, reflected in our revenues. Now moving to year-to-date results, you know, our year-to-date results showed growth of 1.8% in adjusted EBITDA driven by many of the same factors affecting our fourth quarter growth. The Barnett and Gulfstar non-cash deferred revenue step-downs totaled $109 million in 2020 versus 2019, while the net impact of commodity price fluctuations on our inventory line fill position created an $8 million non-cash reduction in EBITDA. So without those non-cash comparability items, full-year adjusted EBITDA results were actually up more like 4%, much like our fourth quarter results. And then looking at that by segment, the Transmission Gulf of Mexico assets delivered $41 million of growth with an uplift coming from expansion projects and expense reductions being offset somewhat by lower Gulf of Mexico volumes and the impact that has had on commodity margins in the Tegam area. In the Gulf of Mexico, the total impact of shut-ins from COVID, hurricanes, and the price collapse earlier in 2020 had about a negative $49 million impact to our EBITDA. The Northeast is obviously a huge part of our growth this year, adding $194 million in EBITDA in 2020 versus the prior year, with the overall gathering volumes up 7% and incremental revenues being realized from processing, transportation, and fractionation of gas and NGLs, while at the same time we have been reducing costs. And finally, in the West, it's off by $33 million, largely because of the Barnett MBC payments that ended in June of 2019 and lower Hainesville profits due to lower realized rates being offset somewhat by reduced operating expenses in the West. Otherwise, in the West, our gathered volumes were down about 4%, but they were largely offset by higher rates and the MVCs in the Eagleford due to the renegotiated contract with Chesapeake in December of 2019. So, again, all in all, despite a tough market and a tough hurricane season, we've had a really good year on the backs of cost reductions, northeast performance, and new pipeline projects coming into service on Transcove. I'll now turn the call back over to Alan to discuss our 2021 guidance.

Alan? Okay. Well, thanks, John. And now we're going to turn to our 21 EBITDA guidance metrics. So I want to emphasize that we continue to expect the same level of supportive fundamentals underpinning our base business. for 21. However, we do have more upside potential than we had in 2020 in this plan due in part to upstream transactions that have the potential to drive incremental cash flows across our midstream assets in 21 and beyond, plus an emerging gas storage imbalance caused by the recent higher demand that will likely put a call on gas-directed drilling here in 21 as well. So we're providing our initial EBITDA guidance range of $5.05 to $5.35 billion, with the midpoint up 2% over last year. And we'll get to EBITDA drivers here in just a second on what those specifics are, but let's go through the rest of the guidance here. Our available funds from operations, or AFFO as John described, which will now replace DCF, are expected to be within a range of $3.55 to $3.85 billion, which translates to a per-share range of $2.92 up to $3.16 per share. And importantly, even with a 2.5% increase in the dividend announced earlier in the year, we are still maintaining similar coverage on our dividend, whether looking at the DCF metric or the AFFO metric. And this continues to really underscore the continued safety of our dividends. Our growth capex of $1.0 to $1.2 billion is expected to remain in line with 2020, and this includes known opportunistic upstream acquisitions in the Wamsutter Basin that will be immediately accretive to both credit metrics and earnings. And notably, we still expect to generate free cash flow after capex and dividends, which provide us financial flexibility. And speaking of financial flexibility, we estimate ending the year with a leverage ratio of 4.25, but with the line of sight that we have currently to a targeted 4.2 objective, as we have consistently overachieved on this metric, and I know a lot of you all follow that very closely. We continue to perform very well on that, and we think we've got a lot of things that could help drive us towards that 4.2 or getting to that 4.2 here in 2021. So looking at drivers of our 21 EBITDA guidance, we expect continued northeast GMP growth from the base business and, to a lesser extent, the Bolton Blue Racer acquisition. In our transmission and Gulf of Mexico business, we see Transco growth continuing to add stable EBITDA via the Southeastern Trails Project that was just placed in service ahead of schedule at the end of the year. And We expect late-year contributions to come from our Lighty South expansion, which is now under construction. And additionally, we expect a nice recovery in our Gulf of Mexico earnings this year due to less production outages from hurricanes and the COVID-19 pandemic impacts. Offsets to our EBITDA growth are driven primarily from lower NGL throughput on the jointly-owned Overland Pass Pipelines. lower earnings on our jointly-owned Rocky Mountain midstream business in the DJ Basin, and lower gathering rates from our global resolution in the haynesville with chesapeake energy so these are partial offsets that we do already have built into our guidance and of course on that last note a lot of potential upside to is coming in the haynesville both from a much healthier chesapeake well positioned to develop uh the the haynesville which is very well positioned in this gas market as well as our ability to drive volumes on the upstream properties that we now control. Our takeaway here is that our EBITDA is primarily driven by growth in the base business, with upstream EBITDA accounting for less than 1% of this forecast. We purposely did not include a full year of the upstream EBITDA from these existing producing reserves, because we fully intend to transact during the year in a way that allows us to enjoy midstream cash flow growth in 22 and beyond as we find the right partner to fully exploit the growth available in these high-value properties that we were able to pick up this past year. So we are in a very strong position now to ensure that this acreage is developed quickly and gets turned into fee-based growth on our existing midstream capacity. So we really are excited about the upside potential that we've positioned ourselves for around that business. So in closing, I'll reiterate that intense focus on our natural gas-based strategy has built a business that is steady and predictable with continued moderate growth, improving returns, and free cash flows. Our best-in-class long-haul pipes are in the right place, and our formidable gathering assets are in low-cost basins that will be called on to meet gas demands that continue to grow. We remain bullish on natural gas because we recognize the critical role it plays and will continue to play in both our country's and the world's pursuit of a clean energy future. Natural gas is an important component of today's fuel mix and should be prioritized as one of the most important tools to aggressively displace more carbon-intensive fuels around the world. Williams is focused on sustainable operations, including ready-now solutions to address climate change, and by setting a near-term goal for 2030, we will leverage our natural gas-focused strategy and today's technologies to focus on immediate opportunities to reduce emissions in and around our business. We also are looking forward and anticipating future innovations and technologies that we can use on our key energy networks to deliver on this next phase of energy transition. I also think it is important in light of last week's severe cold weather event to talk about the resiliency and reliability of our natural gas infrastructure. Despite historic cold that enveloped much of the country, Williams did not have to – we did not have to tell any services to our gas transmission customers and, in fact, operated above design capacity on our Northwest pipeline system for a period and delivered flawlessly on a new record three-day peak on the Northwest pipeline system. Our customers expect this from us based on our long history of performance, and we are certainly glad that they do. However, last week's weather demonstrated the importance of a comprehensive energy strategy of the need for a comprehensive energy strategy for the U.S., one that doesn't demonize one energy source over the other, but that includes a mix of energy that does not drive towards singular dependency because of labels imposed by the environmental opposition. And there are important and complex decisions that need to be balanced to address these the things that we all want from our energy sources, reliability, affordability, and balancing the issues of carbon intensity. And when we think about carbon intensity, we really have to consider that from a global perspective. And we believe that when all these factors are accurately weighed and balanced, natural gas will be a very critical part of the energy mix for many more decades to come. So finally, I want to recognize the tremendous efforts of our entire workforce in ensuring the safe and reliable delivery of natural gas to America's cities and communities, not only this last week in the face of severe weather challenges, but amidst the ongoing COVID-19 pandemic. Many of those who benefit from our services may never realize the work needed to ensure the continued access to safe and reliable energy. Our employees are critical infrastructure workers on the front lines of keeping our country's natural gas system operating and flowing, doing so while also enduring power outages and lack of water at their own homes. I am extremely proud of our employees for their efforts to keep our operations running smoothly during these extreme circumstances while also doing the extra mile to keep themselves and their coworkers safe and healthy. And with that, I'll open it up for your questions.

At this time, ladies and gentlemen, if you would like to ask a question, please press star 1 on your telephone keypad. Our first question comes from Jeremy Tonnet with JPMorgan Securities. Your line is now open.

Hi, good morning. Good morning, Jeremy. Good morning. Just wanted to touch base on the CapEx outlook, as you talked about it there, the billion to 1.2. And just wanted to see what's the, you know, the drivers behind that. Could there potentially be CapEx creep, or do you see this as kind of a steady level? And then just if you could expand a bit more on the opportunistic upstream acquisitions in the WAM site or what that is exactly, that would be very helpful. Thanks.

You bet, Jeremy. Thank you. Well, first of all, I would say in our base business, we have about $900 million of capital in what would be our normal base business, so it is a little bit lower than what we've had historically. Um, and that, uh, is about half of that is in T gum. So that includes, uh, whale. It includes, uh, building out lighting South, kind of the final dollars on Southeastern trails and cleanup and so forth on Southeastern trails and some money on the front end of the RA project. So that's kind of the primary drivers there. in Tegon, that's about half of that 900. And then on the balance of that, about two-thirds of that is into Northeast, both finishing up projects as well as getting some new projects started that are driving higher margins for us in the new Northeast and some of that growth. A lot of that investment actually will drive growth in 22 there in the Northeast as well. And then finally, the balance of that is in the west. Some of that is in the Permian, pretty good expansion going on in the Permian, as well as in the Hainesville area, as we're really going to be having to work hard to keep out in front of a lot of drilling activity that's emerging there. there in the Haynesville. So that pretty well rounds that up. The second part of your question around the opportunistic upstream involves us taking advantage of the strong position we had with our midstream assets out there, particularly around the Southland bankruptcy, and we will be in the position of acquiring both the BP acreage out there that's adjacent and intermingled with that as well as the Southland acreage. And we're able, given our position in the bankruptcy there, we were able to pick that up for some very attractive pricing. And as a result now, we're going to be working to gain the right person, the right party to rapidly develop those reserves and take advantage of the latent midstream capacity that we have out there. So we are really excited about that, both in the WAM Sutter, because it's a tremendous amount of value to be driven across our midstream assets by using the PDP cash flows to drive that, as well as in Haynesville, where we're already seeing Chesapeake get very focused on developing the remaining, the northern part of the Haynesville that they hung on to, and as well some very attractive interest coming from parties that were in a process to find the right party to develop. the Hainesville acreage. So I want to make it clear, we have no intention of hanging on to that. We're not going to become an E&P business. There is no ifs, ands, or buts on that front. But this does allow us to put the right parties in place and assure ourselves that we have the right parties in place to take the cash flows off of these assets and put it back into the drill bit to drive midstream cash flows. So really it's turned into something actually a lot more positive than we were expecting, and we really feel like there's a lot of upside from this, both in 21 and as well, though, into 22 and beyond as we attract the capital to develop those reserves. So really, you know, what is normally – an area that might have been a problem for us with all these bankruptcies, we really were able to find a way to really turn some lemons into lemonade there, and we're really excited about the kind of value that's going to be driven out there over the next several years.

And, Jeremy, just to be clear there, and I think it was, but just to reiterate, in our midpoint guidance for growth capital of $1.1 billion, that included those acquisitions of that upstreet bank, which in the WAM Center, And so Alan mentioned a run rate for everything other than that of $900, maybe a little bit more than $900 million. So we paid less than $200 million for those assets, actually significantly less than $200 million, more of a tune of $150 to $160 for that acreage. And we have very little EBITDA on our guidance for that because we're not sure exactly what kind of partnership structure we'll have. If somebody will just buy us out of that acreage, will we partner and see EBITDA uplift? So there's a lot of big upside, I think, that we can see out of that.

Yeah, and one thing, Karen, this is Chad, to note, one of the reasons why I think we were uniquely positioned to step in in this transitional role in Womsutter is the BP asset and the Salton asset are a checkerboard of acreage in Womsutter. And so we were uniquely positioned to acquire this property, put them together as one continuous package, and then move that asset to a producer that can now develop it to its full potential. It was really... locked in a situation where we couldn't have a producer get the full potential out of that acreage because of the checkerboard nature of lawn center. So we're able to clean that up, and now we're going to focus on moving that now contiguous position to a producer that can fully develop it and really reach its full potential.

Got it. That's very helpful color there. Thanks. And just to recap on the CapEx side, sounds like it's a very disciplined approach there, not really expecting any kind of creep over the course of the year from what you guys can see. Is that fair takeaway there?

Yeah, I think, you know, just as we've demonstrated, you know, in the last several years, we continue to impose a lot of capital discipline around our decisions. You know, even last year, lowering, as you recall, the only thing we did move in our guidance last year was was lower in our capex during the year, and then we wound up even including the Blue Racer acquisition coming in under that. So, yes, and I'll tell you, our project execution teams have really been knocking it out of the park in terms of managing costs very tightly, even in a difficult environment like COVID, continue to deliver our projects under budget. So, we feel very good about the capital budget range that we have.

And two key points there. A, you know, we are free cash deposit in 21, so we'll generate more than enough cash to cover our dividends and capital, and it'll allow us to be leveraged a little bit. That's the first important point. The second thing I'd say, you know, we did give you maintenance capital guidance of, I think, at the midpoint, 450. Obviously, we spent under $400 million this year in 2020. It was just artificially low just due to COVID and some issues getting some stuff done in the field. So I wouldn't call that creep. It is going back up from, you know, sub 400 to about 450, but that's kind of what we believe, kind of that run rate to be on maintenance capital.

Got it. That's very helpful. And just one more, if I could. Post the election here, it seems like there's new energy policy coming out of D.C. and could impact federal lands production. Just wondering any thoughts you could share with us on higher level thoughts on energy policy coming out of D.C. and specifically federal lands, how you think about that? Thanks.

yeah i would just say you know i'm going to have michael give you some detail here on the deep water gulf of mexico because obviously that's the area that would most impact us of all of our areas otherwise we're not too terribly impacted by it um but uh but we we've seen maybe a different story than has been, you know, that you're hearing in the media in terms of the actual actions going on out there. And most of the acreage is, you know, ready to develop. But, Michael, if you would kind of share some of the detail that we're seeing there in the D4. Good morning, Jeremy. We are seeing continued permitting activity coming from current administration. Since the executive order came out, we've seen – For applications for permits to drill, already 60 of those have been issued in the Gulf of Mexico, 13 of those being on properties that are delivered to us. And then when you talk about permits for modifications, such as workovers, things of that nature on existing wells, 163 of those have been approved by the current administration, and just under 30 of those are on our asset footprint. So we're seeing a lot of activity for permit approvals out there. In fact, we received our gas pipeline permit after the executive order for the whale project. And they're continuing to process permits. And we had our whale permit for the oil export pipeline already last year. And so we're continuing to work with our producer customers out there. And as you probably know, there's a lot of leases that they've locked up. and a lot of permits that they already had in hand. And so there's a long runway of activity that will continue to occur in the Gulf of Mexico, we believe.

Got it. That's very helpful. Thank you.

Our next question comes from Pernice Satish with Wells Fargo. Your line is now open.

Thanks. Good morning. So now that you're the operator of Blu-ray, sir, can you just elaborate on any of the steps you could take there to increase utilization on the system or capture any of the low-hanging cost synergies?

Yeah, sure. Michael, you would take that? Sure. Good morning. Yeah, there's definitely an opportunity to capture some synergies there, just like we did with the UEO M acquisition that we became the operator on that asset. We rolled that into our Northeast JV system. And we are having those conversations, very similar with Blue Racer, where we can consolidate some of the operations up there, utilize latent capacity in either one of our systems to the benefit of the other. There's a lot of activity currently on our Northeast JV systems up there where our processing is full today, and our fractionation facilities are full as well. And so we would be looking to possibly use some of the BlueRacer capacity should it become available to move some of those volumes over to them, and vice versa, ultimately. So we think there's a lot of definite commercial synergy there, ultimately, and certainly some operational synergies with the teams that are there.

Great. Thanks. And then can you provide any more details that you received from Chesapeake in the Haynesville. Specifically, what is the production at right now of those assets? And any more clarity in terms of when you plan to monetize that?

Sure. Hey, this is Chad. Relatively small amount of existing production, around $30 million a day, kind of pre-last week's cold. That's recovering.

It dropped a bit, but it's recovering.

So not a lot of existing production, around 130 existing wells. But I will first say we were really encouraged to see Chesapeake emerging from bankruptcy as a really healthy customer. So I'll touch on South Mansfield in a second, but just know that they're very active up in the spring ridge area where they remain the owner-operator with two rigs and we think likely going to three rigs. So that was good to see. And in South Mansfield, we did add an additional opportunity where we have $350 to $550 million a day of capacity available from a midstream perspective for development in that area. We closed on that transaction prior to 21, and we've been out now talking to potential partners, and we've seen incredibly robust interest in this asset. It is a contiguous, blocked-up position in some really top-tier, both Hainesville and mid-Bossier markets. area and, again, has available midstream capacity. I would say that we're likely to finalize our partnership strategy over the next couple of months. I expect that we will have a very strong, well-capitalized partner that will operate that asset and will dedicate one to two rigs at any given time to really fill up and utilize that capacity. So we've seen an incredible amount of interest, and I think we're really confident that we're a great partner there, and unlock the potential of that asset. Yeah, and I would just add to that, we are well into that process in terms of finding the right partner on that. We've been very encouraged by the strong level of interest from a number of parties. But we're not waiting around on that. We can move very quickly. Chad just moved very quickly to find the right partner. Great. Thank you.

Our next question comes from Christine Cho with Barclays.

Your line is now open. Thank you. If I could maybe just talk about the high end of the EBITDA range that you gave for 2021. Alan, it sounds like you said it's mostly driven by, you know, your expectations for a call on gas, especially with what went on last week. So is this really driven by G&P volumes, and is it mostly in the northeast I just wasn't sure if, you know, Hainesville and Walmsutter was included in that or if that was more of a post-2021 impact. And have the producers, you know, behind the system in the Northeast started to talk to you about these plans, if that is the case.

Yeah, thank you. Well, Christine, I mean, you're targeting right on the correct issue there. We really developed that plan before we've seen this recent call. And, you know, I think this week we're going to see a huge pull on natural gas from storage this week and likely take us down below the five-year average. And meanwhile, production, you know, we really haven't seen the activity in production to stabilize that decline in storage activity. And the places that are going to be able to respond to that quickly are going to be Hainesville and the Marcellus and Utica. And so we didn't have any of that in our plans when we laid this plan out. So certainly that is upside to this. In fact, most of the growth in the northeast was really just margin expansion. It wasn't really a lot of volume, expected volume growth. The growth that we've had there has really just been margin expansion. So that is certainly an attractive upside for us there. It is not based on the upstream at all. In fact, we basically assumed we just got the PDPs flowing in here for Hainesville and Wamsutter, assuming a July kind of finality to finding the right owner. So we only have cash flows in here. on the Wamsutter area through about July. And in the Hainesville, we do have the PDPs in there, but we also have development capital that likely would be coming out of there if that gets done. So I would be the first to admit that we've been very conservative on the upstream side of this because we really wanted to leave ourselves full flexibility, and we didn't need to be able to either fully dispose of the asset if the right price was there. But at the end of the day, we just wanted to have full flexibility, so we were very conservative in how we included the value of those upstream positions. And you're right, I think, you know, Upsides are probably mostly related to volumes in the Northeast, but I would also say we were we remain pretty conservative in the forecast that we have for the deep water and any other area frankly that can contribute from a gas side so And then I would say the other area that we've included we have assumed rising cost versus 2020 did a great job in 2020 and on cost, and our 21 does assume that we've got some come back on cost that, frankly, the team's just been doing a terrific job of managing. And so that's another area of opportunity for us as well.

Just a couple things maybe to play on that a little bit with Alan. On Transco, we were successful in 2020 selling short-term firms. both on transfer and Northwest Pipe, and we don't have a repeat of that really in any meaningful way in 21. That possibility still exists. We had all that hurricane activity in 2020, and our team reversed most of that in the forecast, but not all of that. You know, we do expect that it could be a little bit more active in 21. And so if that doesn't happen, I think there's upside, you know, some additional EBITDA just from some additional EBITDA we just didn't put in that was left in that's just conservative. for hurricane activity. And then, you know, Alan pointed on the expenses. So, some of this is on TGOM, too.

Okay. That's helpful. And then, actually, if we can move on to the weather impacts that we've seen in, you know, Texas and to a lesser extent in Mid-Con, is all of your natural gas storage in Texas contracted to third parties, or do you have some for your own use? And how should we think last week's weather impacted you guys? It sounded like it was pretty neutral from a financial perspective in your prepared remarks, but any color there would be helpful.

Yeah, thanks, Christine. First of all, we actually don't have any gas storage in Texas. So the storage on Transco is at Washington, which is kind of the middle part of the state. um by opelousis and so that's where that's where the storage facilities are and um that so there really wasn't a whole lot of you know impact there uh and obviously transco is designed to flow from that area designed to flow to the north and east not not back into texas um in terms of the impact to us i would say you know it was pretty small in terms of the impact of our gathering volumes, just because we have such a dispersed business and the vast majority of our gathering is either northeast or in the Rockies, which we're not directly impacted. But I would just say as well, our team did a great job of doing things like selling fuel and shrink that we had bought at first of the month, turning down our processing recoveries and then selling that fuel and shrink back into the market. And so I would tell you that, you know, I think net-net it's going to be a little bit of a positive for us in terms of the way we manage things. But we certainly saw a lot of outage in the Oklahoma, Texas, and Louisiana area on our gathering systems. It's just a pretty small piece of our overall percentage of the business.

Got it. Thank you.

Our next question comes from Gabriel Maureen with Mizuho. Your line is open.

Hey, good morning, everyone. I just had one in terms of basis in Appalachia and just how you're thinking about that within your forecast and kind of the cadence of the Northeast. Is there anything, you know, in your forecast for producers toggling gas on and off, particularly during the shoulder seasons?

uh gabe no i would just say we pretty well just stick with the producers forecast you know that they've given us and obviously they take that into consideration um and you know if the prices come up they'll turn some volumes on and and but you know a lot of the producers have their own takeaway capacity and certainly um you know that that amount that they're selling into that spot basis is pretty small But it does, you know, it does impact their ability to sell incremental volumes if they have that. But we're not, that isn't driven a lot into our calculation. We basically just take what the producers are saying they're going to do. And to the degree that we have a line of sight for how that's going to happen, that's how we've seen it. And so far they've been, you know, pretty accurate, consistently pretty accurate in the way that they've been forecasting that they know their reserves and they know the market. I will say that obviously excited about Lighting South coming on and opening up additional capacity. That's about 580 million a day of additional takeaway capacity out of the Northeast. And our team has got a really good head start on Lighting South on the project there. And so again, great execution going on by that team. And then ultimately, REA will be additional takeaway out of that area as well. So we're really – those projects are very important from a synergy standpoint because not only do we get nice returns on the transmission, we get the gathering volume up with upstream of that as well. And now to the question on shut-ins in response to pricing. We certainly can still see producers respond to market dynamics, but I do think 21 is going to look different than 20. We're coming into, you know, out of the winter at a much different storage inventory level. We're seeing natural gas prices stronger than they were a year ago. We do think that there will be bases that will continue to represent the value of our existing infrastructure. We're going to see some more LNG demand come online this year, and we're going to continue to see the need for growth and supply out of the Northeast. So I'm not sure we'll see basis that will drive shut-in activity, but I think it will continue to reinforce the value of having infrastructure to move from Appalachia to growing markets. But we'll certainly keep an eye on it.

Thank you. And then maybe if I can just ask, it's kind of interesting that a lot more time has been spent on the call on upstream asset sales and midstream asset sales, but maybe if I can ask kind of where the latest thinking is on additional midstream sale, asset sales, and whether I guess some of the impairments on assets like Rocky Mountain Midstream kind of change your thinking and evaluation about how those assets might fit with the portfolio longer term?

Yeah, I really think so, Gabe. I think we were, you know, as to the RMM impairment that we took, you know, that's been an equity-level investment. So, you know, obviously it's very different than along the way you value a consolidated asset where, you know, you take the total cash flows on the asset over time. But in those, you actually have to market to market effectively. And we've given some of the sales that we've seen in the space, we've seen some lower markings on the value of assets, and that's what drives those kind of considerations. And in fact, as a result of that, it would probably drive us in the other direction because it's basically saying there's a weak market right now for G&P assets. And if that's true, then this probably wouldn't be the right time to be liquidating assets. So not to say we don't constantly have our eyes open to structure and things that can add value from that, But I think, you know, we're in a position of getting to our leverage metrics in a pretty straightforward manner, and particularly these upstream assets would be a really nice tool for that as well.

And so right now, I would tell you, I'm not sure it's the very best time to be trying to liquidate those assets. But, Gabe, one thing I think that is interesting, you know, when we were thinking about this early in 2020, it was actually – In January of 2020, I think we were heavy in the middle of thinking about trying to market some of our assets in the West. And there were a lot of question marks at the time around Chesapeake, what was going to happen in Chesapeake, what was going to happen in the West in general. And I think now a lot of those questions are cleared up, and you can see through our performance. I think we demonstrated the resiliency through diversification, not that we didn't have issues in certain basins, but we had good performance in other basins, and it kind of washes itself out. And so what I would say is while the market's probably a little bit weaker, I think our demonstrated performance on the business is a little bit stronger, a little bit clearer now a year later. So I'm not sure what all that means, but – I think the opportunity is still out there, and I think we've demonstrated strong performance, which should help if we ever wanted to pursue that. Thanks, John. Thanks, John.

Our next question comes from Spiro Dunas with Credit Suisse. Your line is now open.

Hey, morning, everybody. First question is just on how you're thinking about sustainable EBITDA growth in the current environment. You guys, once again, highlighted about a $12 billion backlog on transmission projects. And so, simplistically, the way I thought about it was kind of reflects about 10 years of growth at current CapEx levels, which I guess was enough to grow EBITDA about 2% this year in 2021. So, just curious if based on that backlog of projects in front of you, do you think sustaining 2% annual growth for the next decade or so is maybe a floor or something you deem sort of easily achievable?

Yeah, I'm going to have Michael speak to that backlog on projects. But I think you have to be careful about drawing that kind of conclusion. You know, most of the projects that we've been doing have been 6%. We still were rolling off a lot of deferred revenue this last year and a little bit into 21. So I think you have to be careful about that. making those kind of broad assumptions. So for instance, when the deep water business comes on, that's going to be a very high growth rate on a fairly low amount of capital. And in the Northeast, sometimes we get, you know, nice surges of margin based on very high incremental return opportunities as they come to us. And on the other hand, you know, we have a decline in built, you know, that's just part of the gathering business. If there's an area that's not growing, there's a client that's working against it all the time. But I would tell you that it's more complex than taking a billion dollars and saying that that produces 2%. On the other hand, I would say I think, you know, we feel very comfortable with a 2% growth rate. If we are investing a billion dollars, we feel very comfortable with achieving a 2% growth rate. But given some of the upsides that we've got in some of these areas, uh, I, I think that probably would be kind of considered a floor, um, from my perspective on that. So Mike, we might talk about. Yeah, we, uh, we look at that backlog and it's really dynamic because we have a lot of projects that come into that backlog and then we execute on a lot of those projects and, you know, Southeastern trail is one that came out of the backlog, like South, came out of that backlog and became an execution project, and regional energy access will be the same once we get that filing underway and get our permitting underway. So you'll continue to see projects come out of our backlog and move into the execution phase over the next several years. There's a plethora of opportunities along the Transco corridor to take advantage of coal-fired generation that's going to come offline and ultimately be converted to gas and renewables. And I think from the activities we've seen in Texas and Oklahoma over the last week, there definitely needs to be a mixture of energy generation resources in the mix in order to diversify across fuel sources. And so I'm a true believer in that. Our company is definitely a natural gas-focused company. Now that I'm adding in some renewable mix into the into the play there to take advantage of some opportunities we have. But ultimately, on the Transco system, we're going to be able to drive a lot of new capital investment there on the fact of coal-fired generation going away. And then lastly, our emissions reduction program project. We have upwards of $1.6 to $1.7 billion of investment opportunity there on the Transco system. and likely replacing a large component of our reciprocating compression to do modern either electric drives or gas turbines to reduce our emissions footprint there along the Transco corridor. So there's definitely a lot of investment opportunity that we envision coming in the future for Transco's asset footprint.

Got it. Appreciate the color on that. Second one, just briefly going back to Blue Racer, can you just talk about some of the circumstances that led up to you increasing your interest there and how you're thinking about the remaining stake you still don't own?

Yeah. So just to, you know, just to remind people the ownership there, Blue Racer is, is, and Cayman, too, by the way, is no longer an entity. It'll now be Blue Racer or Midstream Holdings. Thank you. And so now that is owned effectively 50% by Williams and 50% by First Reserve. The parties that got out were primarily driven a consortium by NCAP Flat Rock Midstream. And so that group, you know, has been an investor in that for a long time, along with some of the management from Cayman 2. And obviously, they had held on to that much longer than a typical private equity shop likes to. And we worked with them to liquidate them at the appropriate time. We think we bought it right and at the right time. And particularly given the large amount of synergies that we have available to extract from that business. And so we're excited about the transaction. I can tell you, we were super patient. We've been wanting to gain control of that asset and exploit the synergies between both our UEOM system and our Ohio Valley River. We've been wanting to, you know, take advantage of those. And it's been hard to to not, but we've been patient, and I think our patience paid off, and we were able to pick that up at a very attractive value. So that's kind of how I would offer that, but I think at the end of the day, it was a private equity-held investment that was needing to get out because that was the last investment they had in one of their funds, and they were wanting to get that liquidated. And it was a pretty complicated structure, so not only did we get it, we thought it was a really good value, but We were the majority owner of Cayman, which was half of the owner in Blue Racer, and there were two different boards that managed the joint venture. There was a lot of governance complexity, and so we really cleaned up that asset governance. When you think about the two large joint ventures in that part of the system now, you have our OVM system, which is 55% Williams, 35% CPPIB, and you have Blue Racer, which is now 50% Williams and 50%. the much cleaner landscape for us to try to work on just creating value and optimizing value.

Got it. Thanks for the call, guys. Be well, everybody.

Our next question comes from Tristan Richardson with Truist Securities. Your line is now open.

Hey, good morning, guys. Appreciate all the comments on the Gulf of Mexico and around the outsized impact in 2020. I think you noted in the slides 49 million of downtime impact there. Question just on 2021, what a normalized season looks like or sort of just a regular storm season that maybe what you have baked in or generally your assumptions for 2021?

Mike, are you going to take that? Yeah, I would say normally our team does put some hurricane impacts in there, and it's usually between $5 and $10 million of epidemic impact based on what a non-hurricane year would look like. So it's not a huge reduction that we would typically see there on a normal year that we build into our forecast.

And I think I alluded to a minute ago, I think when Christine was asking questions, you know, of that 49 negative impact we had in 2020 versus 2019, we've got all but about 10 million of that reversing itself in 2021. So we still held 10 million of even maybe a little bit more than normal outsized negative into 2021 as well. Because the 49 was a comparison to 19. That's right.

That's helpful. Appreciate it, John. And then just thinking about where your commodity exposure lies in the GMP businesses, could you maybe just give a quick high level of, you know, maybe where the most POP lies versus key poll, where we should think about those exposures regionally, just at a high level?

Yeah, you know, we have very little, and I'll just start it off with it, you know, compared to the The way the business used to be shut, we just had very little. And it's getting harder and harder to see, frankly. But the areas that we do have the most exposure are keypole, primarily keypole agreement in our Opal area. And we do have some exposure in the Gulf Coast as well. So you'll see that listed as Southwest Wyoming when I say Opal. I think in our EBITDA break, I think it shows you the Southwest Wyoming area. So that's the majority of that exposure. And, again, though, we do have some margin in places like our discovery asset in the people out of Gulf of Mexico. But I think total and plan on a gross margin basis, we're down to well under 2% now. So it's a really, really small number. And one of the other benefits of WAM Center, we have a small amount in WAM Center, but we will actually modernize those contracts to be fee-based as part of our cleanup of the Longsutter Basin, so we'll further reduce a little bit our existing POL and T-POL contracts. I might just add, so we don't skip over one thing. We do have areas like in the Barnett where our gathering contracts are exposed. They have a floor, but then they're exposed to gas prices above that. Similarly, in Laurel Mountain Midstream, we have those contracts basically are base level, but then they have exposure to gas price above that. So we do have some contracts that have direct gas price exposure in them, and Barnett and Lower Mountain are the two areas that really have those.

Thank you guys very much.

Our next question comes from Derek Walker with Bank of America. Your line is now open.

Thanks, guys. I know we're over the hour here, so just two quick ones from me. Alan, I think in your formal remarks, you talked about line of sight on the leverage side with potential to have that, I think, that 4.2 target achieved in 2021. Can you just talk about some of the drivers that could get into that? I know your guidance is the 4.25, but how do you think about some of the drivers to get into that 4.2 in 2021?

Yeah, well, I would say there's really two areas there. One is Obviously, the obvious, when I talked with Christine earlier about some of the upsides, drivers for 21 or EBITDA, obviously that's the simple way for us and probably, you know, I would say most probable. But as well, you know, I think capital reductions that would come to us associated with the transactions on the upstream as well, where we would lay off some of that capital responsibility to third parties. So those are the two kind of easy ways to get there, I would say. And obviously the EBITDA upside is the one that probably has the clearest line of sight too.

Got it. And then maybe just a quick one. Just on the, are you seeing much, I know there's a lot of commentary around kind of the upstream side of things, but are you seeing much difference in the behavior X kind of bankruptcies from public EMPs versus private EMPs, and what areas are you seeing some of those big differences, if any?

Yeah, you know, I've noticed that a lot of analysts are starting to pick up on that, and clearly, you know, the public markets have just been sour about spending on anything, and I think the private markets have been seeing the opportunity and taking advantage of that pullback. We certainly are seeing that Hainesville is the is the poster child for that for sure, where there's so much private capital that's going to work there. And it's an attractive place because you don't have a lot of the basis risk that you have to manage and the long-haul capacity risk that you have to manage coming out of the Marcello. So it's an easy place to go in in a fairly de-risked manner. And that's what's attracting, as Chad mentioned, that's also what's attracting a lot of capital to our opportunity there in Hainesville. So that's definitely the money that can come in and get out pretty quickly by turning a bit and turning it into cash up against the current Ford Strip, which is what a lot of private parties are doing, is what we're seeing. So it's a fairly de-risked model, and they're just looking around the various basins for opportunities to do that. But But clearly in our line of sight, Haynesville is the area that's getting the most attention in that regard. Appreciate it. Thank you very much, Alan.

Our next question will be from Colton Bean with Tudor Pickering and Holt. Your line is now open.

Morning. So just wanted to follow up on some of the comments there around volumes. It sounded like for GNP, the guidance assumes something close to maintenance in the Northeast. Is that a fair characterization? And then just any high-level comments on what you're looking for in the West would be appreciated. Mike?

Yeah, I'd say on the gathering side, we are looking at most likely maintenance-type activities on the gathering side. But on the processing side, and it's highly dependent on the producer in the basin in the Northeast, just to be clear. There are some upsides and downsides, but On the processing side, we are seeing a large influx of volumes year over year that we will continue to enjoy. Nice margins there. Our processing at Oak Grove is at capacity, and we're finishing up our THP-3 there. It should be online next month. And our fractionation facilities, as I said earlier, are at the capacity level as well. So we're seeing a lot of activity continuing in the West Virginia, Ohio, Southwest Virginia area. That will drive a lot of volumes to our processing facilities where we see the upside occurring to our 2020 performance in 2021.

One thing that you'll see in the northeast is even though our volumes don't look like they're going up that much in the northeast, Laurel Mountain Midstream, Chevron pulled back, EQCT is taking that production over. We have an MVC, so it really doesn't have a meaningful revenue impact to us, but that volume is declining there, and so that's muting maybe a little bit. the volume growth you otherwise would have seen in the northeast, especially around Marcellus South.

And just to be clear there, it's a little bit confusing sometimes in the southwest Marcellus and West Virginia area there because we gather some of that gas, and then we spin it off to third parties, to other third-party processors because we've been full. And so once we have that capacity built, we get that business back. And so that's not obvious sometimes that we don't. process everything we gather, and we don't gather everything we process. And so those two numbers don't go hand-in-hand necessarily.

And on the west, where we're seeing the least activity is the Eagleford, which has NBC protection.

So though you might see some additional volume decline, it's NBC protected in the Eagleford, and you should see activity increasing in Hainesville. And those gas-directed

The majority of our west beyond Eagleford is gas-directed activity, and with a relatively robust gas price, we should see good activity on the gas side of that system.

And I'd say also, as it relates to the west, in 2021, you know, you're seeing the back end of not as much production activity in Haynesville as we'll see now with Chesapeake back recapitalized and new producers in the South Mansfield that we're working with. And in the WAMP Center, the same is happening. The WAMP Center BP wasn't really active, nor was Dauphin, obviously, because they were in bankruptcy. And so we're not going to see that in 21, but in 22, I think you'll see those volumes start to turn back around.

Great. Appreciate that detail. And just a final one for me. I mean, you all have highlighted a couple of times how you will be either near or at the long-term leverage target to exit this year. So as you look forward, can you just update us on where you stand on capital allocation, whether that be further debt reduction, you know, looking at a buyback authorization or supplementing the existing backlog with some renewables investments? Appreciate it.

Yeah, I would just say, you know, that question obviously is something that we've been, you know, saying for quite some time will be coming to us. And I think as we get to this end of this year, obviously, that that will be but make no you know mistake about it the first thing and we've been very clear on this is is debt reduction is the first place to go with that uh once we get beyond that things like um investing in our rate base on transco on things like the emission reduction project will be put up against other alternatives for that capital reduction, whether that's further debt reduction or share buyback. And those are the things that would be in competition for that further capital allocation as we get into that year. But it's an interesting dilemma because not very many people, in fact, I don't know if I could describe to you too many other pipelines that are in the position of being able to invest in the rate-based And for us, the cost of capital, it just hasn't met that return hurdle internally. So in the past, it really hadn't been thought of as an opportunity. But as we think about the emission reduction project, that's a very sizable capital investment opportunity that will make a decision on that versus other alternatives from a cost of capital standpoint. So I think that's the best color I can give you on that at this point.

Great. Thank you.

Our last question will come from Michael Lapides with Goldman Sachs. Your line is open.

Hey, guys. Thank you for taking my questions. One easy one, which is OpEx and G&A in 21 over 20, up, down, flattish. Just trying to look for a little direction. And then second, can you remind us, what's the expected CapEx for regional energy access? And what are the key permitting milestones we need to look for? Mike, why don't you take both of those?

Yeah, on regional energy access, we have publicly stated in our pre-filing was a $760 million a day project. I think by the time we file here in a few weeks, we'll be at or above that level. And what we've said in the past is it's between $800 million and $1 billion of investment, and we're probably at the lower end of that. our filing activity looks. So, yeah, John, I'm going to take the first part of your question.

Yeah, so on operating costs, and I'm going to drag you through some numbers here real quick, but if you look in our analyst package, and if you look at the operating costs in each of our segments, and you compare 2019 to 2020, you'll see a number of a $223 million reduction in operating expense. But I want to be clear on that. 2019 had incremental expenses because we did a voluntary severance program and we're cutting costs. So 2019 costs were elevated. 2020 costs were low because we changed the benefits program around days off. And anyway, it resulted in a $40 million benefit 2020 expenses. I'm dragging through all that to say that $223 million reduction in expenses on a normalized adjusted EBITDA basis is only a $100 million reduction, $103 million reduction in expenses between 2019 and 2020. And that includes an $11 million increase in property and in operating taxes, ad valum taxes. And so we saved about $114 million between 19 and 20. We think about 70% of that will stick going into 21. So 30% of that will revert. So we'll see costs go up about $30 million just due to operating costs kind of not retaining all that savings. And then operating taxes probably go up to another 20 to 25 million. So you're looking at probably $50 million of total expense increases in 21. So great job. We're retaining 70% of our cost savings.

Thank you. Thank you. Super helpful. I'll follow up with your team offline. Much appreciated, guys. Okay. Thank you all.

So now I'll turn the call over to Alan Armstrong for closing comments.

Well, great. Well, thank you all very much for joining us today. We really are excited to continue to produce such predictable cash flows from the business, and we're really excited about some of the catalysts for growth that really will drive beyond 21 and as well give us some upside here for 21. So thank you for your interest, and stay safe and healthy.

This concludes today's conference call. You may now disconnect.