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 Juvane, Vice President of Investor Relations. Please go ahead. Thanks, Lindy. 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 Micheal Dunn, our Chief Operating Officer, Lane Wilson, our General Counsel, and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks, and you should review it. 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. With that, I'll turn it over to Alan Armstrong. Great, 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. It yet again illustrates the stability and predictability of our business. 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 the same four-year period. That also, during the same period, we dramatically improved our credit metrics through our asset sale program. Really a nice steady period here of very predictable growth and balance sheet improvement. 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 Caiman II 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. 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 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 the 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. 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. 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 G&P segment, and a catch- up of minimum volume commitment EBITDA from a favorable Wamsutter 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%. 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%. 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 tax, as where 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 derives from cash from operations and is before all capital spending, including before maintenance capital. 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 AFFO 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. Distributable 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. To that point, our total capital spending for the year was 40% less than last year. Our spending this year included the acquisition of most of the remaining interest in the Caiman II 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. 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 dividend 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. This year, our debt-to-EBITDA metrics ended at 4.35x down from 4.39x at the end of 2019. 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. 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 Gulfstar platform. As a reminder of deferred revenue, we received significant upfront cash payments several years ago from the Deepwater producer. We did not recognize revenue at that time. We have been amortizing the payments we previously received in the income over the last several years. 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. With or without those non-cash items, our EBITDA was up over 4%. Our Transmission & 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 Hillabee Phase II project that came into service in the second quarter of 2020, and the Southeastern Trail 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 profits 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 G&P 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. On the West, our West segment was down about $8 million compared to 2019. 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 Eagle Ford 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 Haynesville, Eagle Ford, and Wamsutter. Of note, each of these basins were impacted by a customer bankruptcy. With the Southland re-emergence filing a couple of weeks ago, all those bankruptcies should be resolved soon. Also of note, in two of those three basins where we saw majority of our volumes decline, specifically in the Wamsutter and Eagle Ford, our revenues are protected by MVCs. Overall, the reduced volumes only had a small impact on revenues. Just as with our other segments, the West experienced lower costs of 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. It was something that we had received from a third-party compression provider. We also had lower JV EBITDA in the fourth quarter of 2020 of about $4 million, with most of that coming from lower OPPL profits. Again, though, our partner on OPPL kept us whole, as I mentioned a minute ago, reflected in our revenues. Moving to year-to-date results. 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. Without those non-cash comparability items, full year adjusted EBITDA results were actually up more like 4%, much like our fourth quarter results. 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 T&GOM area. In the Gulf of Mexico, the total impact of shut-ins from COVID-19, hurricanes, and the price collapse earlier in 2020 had about a - $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. Finally, in the West, it's off by $33 million, largely because of the Barnett MVC payments that ended in June of 2019 and lower Haynesville 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%, they were largely offset by higher rates and the MVCs in the Eagle Ford due to the renegotiated contract with Chesapeake in December of 2019. 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 our 2021 guidance. Alan? Okay. Well, thanks, John. Now we're going to turn to our 2021 EBITDA guidance metrics. I want to emphasize that we continue to expect the same level of supportive fundamentals underpinning our base business for 2021. 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 2021 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 2021 as well. We're providing our initial EBITDA guidance range of $5.05 billion-$5.35 billion, with the midpoint up 2% over last year. We'll get to EBITDA drivers here in just a second on what those specifics are, 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 billion-$3.85 billion, which translates to a per share range of $2.92-$3.16 per share. 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. This continues to really underscore the continued safety of our dividend. Our growth CapEx of $1.0 billion-$1.2 billion is expected to remain in line with 2020, this includes known opportunistic upstream acquisitions in the Wamsutter basin that will be immediately accretive to both credit metrics and earnings. Notably, we still expect to generate free cash flow after CapEx and dividends, which provide us financial flexibility. 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. I know a lot of you all have followed that very closely, and 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. We're getting to that 4.2 here in 2021. Looking at drivers of our 2021 EBITDA guidance, we expect continued Northeast G&P growth from the base business and, to a lesser extent, the bolt-on Blue Racer acquisition. In our Transmission in Gulf of Mexico business, we see Transco growth continuing to add stable EBITDA via the Southeastern Trail project that was just placed in service ahead of schedule at the end of the year. We expect late-year contributions to come from our Leidy South expansion, which is now under construction. 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 Pipeline, lower earnings on our jointly owned Rocky Mountain Midstream business in the D-J basin, and lower gathering rates from our global resolution in the Haynesville with Chesapeake Energy. These are partial offsets that we do already have built into our guidance. Of course, on that last note, a lot of potential upside too is coming in the Haynesville, both from a much healthier Chesapeake, well-positioned to develop, 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 2022 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. 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. We really are excited about the upside potential that we've positioned ourselves for around that business. 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 we did not have to curtail 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. We are certainly glad that they do. 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 is not derived towards singular dependency because of labels imposed by the environmental opposition. There are important and complex decisions that need to be balanced to address the things that we all want from our energy sources, reliability, affordability, and balancing the issues of carbon intensity. When we think about carbon intensity, we really have to consider that from the global perspective. 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. 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 amid 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 going the extra mile to keep themselves and their coworkers safe and healthy. 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 one on your telephone keypad. Our first question comes from Jeremy Tonet with JP Morgan Securities. Your line is now open. Hi, good morning. Morning, Jeremy. Just wanted to touch base on the CapEx outlook as you talked about there, the $1 billion-$1.2 billion. Just wanted to see what's the drivers behind that. Could there potentially be CapEx creep or do you see this as kind of a steady level? Just if you could expand a bit more on the opportunistic upstream acquisitions in the Wamsutter, 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. It is a little bit lower than what we've had historically. About half of that is in T&GOM. That includes Flail, it includes building out Leidy South, kind of the final dollars on Southeastern Trail and cleanup and so forth on Southeastern Trail, and some money on the front end of the REA project. That's kind of the primary drivers there in T&GOM. That's about half of that 900. On the balance of that, about 2/3 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 Northeast and some of that growth. A lot of that investment actually will drive growth in 2022 there in the Northeast as well. 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 Haynesville 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 in the Haynesville. 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. We will be in the position of acquiring both the BP acreage out there that's adjacent and intermingled with that, as well as Southland acreage. Given our position in the bankruptcy there, we were able to pick that up for some very attractive pricing. 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. We are really excited about that, both in Wamsutter, because there'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 the Haynesville, where we're already seeing Chesapeake get very focused on developing the remaining Northern part of the Haynesville that they hung on to, and as well, some very attractive interest coming from parties that we're in a process to find the right party to develop the Haynesville acreage. 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 if, ands, or buts on that front. 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 flow. Really, has 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 2021 and as well, though, into 2022 and beyond, as we attract the capital to develop those reserves. Really, 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. We're really excited about the kind of value that's going to be driven out there over the next several years. Jeremy, just to be clear there, 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 E&P acreage in the Wamsutter. Alan mentioned a run rate for everything other than that of $900, maybe a little bit more than $900 million. We paid less than $200 million for those assets. Actually, significantly less than $200 million, more to the tune of $150 million-$160 million for that acreage. We have very little EBITDA in 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 for this? There's a lot of big upside, I think, that we can see out of that. Yeah. One thing, Jeremy, this is Chad. To note, one of the reasons why I think we were uniquely positioned to step in in this transitional role in Wamsutter is the BP's and the Southland assets are a checkerboard of acreage in Wamsutter. We were uniquely positioned to acquire those properties, put them together as one contiguous 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 Wamsutter. We're able to clean that up, and now we're going to focus on moving that to now a 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. 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 a fair takeaway there? Yeah, I think, just as we've demonstrated in the last several years, we continue to impose a lot of capital discipline around our decisions. Even last year, lowering, as you recall, the only thing we did move in our guidance last year, was lowering our CapEx during the year. We wound up even including the Blue Racer acquisition coming in under that. 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. We feel very good about the capital budget management we have. Two key points there. A, we are free cash flow positive in 2021, we'll generate more than enough cash to cover our dividends and capital, and it'll allow us to deleverage a little bit. That's the first important point. The second thing I'd say, we did give you maintenance capital guidance of, I think, at the midpoint, $450. Obviously, we spent under $400 million this year in 2019, 2020. It was just artificially low just due to COVID and some issues getting some stuff done in the field. I wouldn't call that creep. It is going back up from sub $400 to about $450, but that's kind of what we believe that run rate to be on maintenance capital. Got it. That's very helpful. 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, I'm going to have Mike give you some detail here on the deepwater 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. We've seen maybe a different story than you're hearing in the media in terms of the actual actions going on out there. Most of the acreage is ready to develop. If Micheal, if you would kind of share some of the detail that we're seeing there in the deepwater. 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. 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 December 30 of those are on our asset footprint. 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. We had our Whale permit for the Oil Export Pipeline already last year. We're continuing to work with our producer customers out there. As you probably know, there's a lot of leases that they've locked up and a lot of permits that they already have in hand. 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 Praneeth Satish with Wells Fargo. Your line is now open. Thanks. Good morning. Now that you're the operator of Blue Racer, 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. Micheal, are you going to take that? Sure. Good morning. There's definitely an opportunity to capture some synergies there, just like we did with the UEOM acquisition that we became the operator on that asset. We rolled that into our Northeast JV. We are having those conversations, pretty 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. Our fractionation facilities are full as well. We would be looking to possibly use some of the Blue Racer capacity should it become available to move some of those volumes over to them, and vice versa, ultimately. 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. Can you provide any more details on the producing assets that you received from Chesapeake in the Haynesville? Specifically, what is the production at right now of those assets? Any more clarity in terms of when you plan to monetize that? Yeah, sure. This is Chad. Relatively small amount of existing production, around $30 million a day, kind of pre last week's pull. That's recovering. That had dropped a bit, is recovering. Not a lot of existing production, around 130 existing wells. I will first say we were really encouraged to see Chesapeake emerging from bankruptcy as a really healthy customer. 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. That was good to see. In South Mansfield, we view that as an additional opportunity where we have $350 million- $550 million a day of capacity available from a midstream perspective for development in that area. We closed on that transaction prior to 2021. We've been out now talking to potential partners, and we've seen incredibly robust interest in this asset. It is a contiguous, locked-up position in some really top tier, both Haynesville and Mid-Bossier area. 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. We've seen an incredible amount of interest, and I think we're really confident that we're going to find a great partner there and unlock the potential of that asset. 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. We're not waiting around on that. We've moved very quickly. Chad and his team 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 your expectations for a call on gas, especially with what went on last week. Is this really driven by G&P volumes, and is it mostly in the Northeast? I just wasn't sure if Haynesville and Wamsutter was included in that, or if that was more of a post 2021 impact. Have the producers behind the system in the Northeast started to talk to you about these plans, if that is the case? Yeah. Thank you. Well, Christine, you're targeting right on the correct issue there. We really developed that plan before we've seen this recent call. I think this week we're going to see a huge pull on natural gas from storage this week, likely take us down below the five-year average. Meanwhile, production, we really haven't seen the activity in production to stabilize that decline in storage. The places that are going to be able to respond to that quickly are going to be Haynesville and the Marcellus and Utica. We didn't have any of that in our plans when we laid this plan out. 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 expected volume growth. The growth that we've had there has really just been margin expansion. That is certainly an attractive upside for us there. It is not based on the upstream at all. In fact, we just got the PDPs flowing in here for Haynesville and Wamsutter, assuming a July kind of finality to finding the right owner. We only have cash flows in here on the Wamsutter area through about July. In the Haynesville, 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. I would be the first to admit that we've been very conservative on the upstream side of this because we really want to leave ourselves full flexibility, to be able to either fully dispose of the asset if the right price was there. 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. You're right, I think, the upsides are probably mostly related to volumes in the Northeast. I would also say 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. Then I would say the other area that we've included, we have assumed rising cost versus 2020. We did a great job in 2020 on cost, and our 2021 does assume that we've got some comeback on cost that frankly, the team's just been doing a terrific job of managing. So that's another area of opportunity for us as well. Just a couple of things, maybe to play on that a little bit, with Alan. On Transco, we were successful in 2020. On short-term firm, both on Transco and Northwest Pipeline, we don't have a repeat of that really in any meaningful way in 2021. That possibility still exists. We had all that hurricane activity in 2020, and our teams reversed most of that in the forecast, but not all of that. We do expect that to be a little bit more active in 2021. If that doesn't happen, I think there's upside of some additional EBITDA we just didn't put in that was at the end that's just conservative for hurricane activity. Then, Alan pointed out the expenses. Some of this is on Tejas too. Okay, that's helpful. Then actually, if we can move on to the weather impacts that we've seen in Texas and to a lesser extent in MidCont. Is all of your natural gas storage in Texas contracted to third parties, or do you have some for your own use? 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. Thanks, Christine. First of all, we actually don't have any gas storage in Texas. The storage on Transco is at Washington, which is kind of the middle part of the state, by Opelousas. That's where the storage facilities are, there really wasn't a whole lot of impact there. Obviously Transco's designed to flow from that area, designed to flow to the North and East, not back into Texas. In terms of the impact to us, I would say, it was pretty small in terms of the impact to 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 were not directly impacted. 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 the first of the month. Turning down our processing recoveries and then selling that fuel and shrink back into the market. I would tell you that, 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. 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 Moreen 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, in your forecast for producers toggling gas on and off, particularly during the shoulder seasons? Gabe, no. I would just say we pretty well just stick with the producers' forecast that they've given us, obviously, they take that into consideration. If the prices come up, they'll turn some volumes on. A lot of the producers have their own takeaway capacity, and certainly, that amount that they're selling into that spot basis is pretty small. It does impact their ability to sell incremental volumes if they have that. 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 include it. So far, they've been pretty accurate, consistently pretty accurate in the way that they've been forecasting that. They know the reserves, and they know the markets. I will say that obviously we're excited about Leidy South coming on and opening up additional capacity. That's about 580 million a day of additional takeaway capacity out of the Northeast. Our team has got a really good head start on Leidy South on the projects there. Again, great execution going on by that team. Ultimately, REA will be additional takeaway out of that area as well. 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 uplifts upstream of that as well. And now to the question on shut-ins in response to price, we certainly could still see producers respond to market dynamics, but I do think 2021 is going to look different than 2020. We're coming 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 basins 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. I'm not sure we'll see basins 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. We'll certainly keep an eye on it. Thank you. Maybe if I can just ask, and it's kind of interesting that a lot more time has been spent on the call on upstream asset sales than 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 don't really think so, Gabe. I think as to the RMM impairment that we took, that's been an equity-level investment. Obviously, it's very different than along the way you value a consolidated asset where you take the total cash flows on the asset over time. In those, you actually have to market-to-market effectively. 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. 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. If that's true, then this probably wouldn't be the right time to be liquidating assets. Not to say we don't constantly have our eyes open to structure and things that can add value from that, but I think we're in a position of getting to our leverage metrics in a pretty straightforward manner, and particularly these upstream assets could be a really nice tool for that as well. Right now, I would tell you, I'm not sure it's the very best time to be trying to liquidate those assets. Gabe, one thing I think that is interesting, when we were thinking about this early in 2020, it was actually in January of 2020, I think we were heavily in the middle of thinking about trying to market some of our assets in the West. There were a lot of question marks at the time around Chesapeake, what was going to happen with Chesapeake, what was going to happen in the West in general. 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. 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. I'm not sure what all that means, but I think the opportunity is still out there, and I think we've demonstrated a strong performance, which should help if we ever wanted to pursue that. Thanks, Al. Thanks, John. Our next question comes from Spiro Dounis 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, 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. Just curious if based on that backlog of projects in front of you, do you think sustaining 2% annual growth call it for the next decade or so is maybe a floor or something you deem sort of easily achievable? Yeah. I'm going to have Micheal speak to that backlog on projects. I think you have to be careful about drawing that kind of conclusion. 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 2021. I think you have to be careful about making those kind of broad assumptions. 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. In the Northeast, sometimes we get nice surges of margin based on very high incremental return opportunities as they come to us. On the other hand, we have a decline built that's just part of the gathering business. If there's an area that's not growing, there's decline that's working against it all the time. I would tell you that it's more complex than taking $1 billion and saying that that produces 2%. On the other hand, I would say, I think we feel very comfortable with a 2% growth rate. If we are investing $1 billion, we feel very comfortable with achieving a 2% growth rate. Given some of the upsides that we've got in some of these areas, I think that probably would be kind of considered a floor from my perspective on that. Mike, you might talk about the Transco projects you mentioned. Yeah. 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. Southeastern Trail is one that came out of the backlog. Leidy South came out of that backlog and became an execution project. Regional Energy Access will be the same once we get that filing underway and get our permitting underway. 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. 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. I'm a true believer in that. Our company is definitely a natural gas-focused company now adding in some renewable mix into the play there to take advantage of some opportunities we have. Ultimately, on the Transco system, we're going to be able to drive a lot of new capital investment there on the back of coal-fired generation going away. Lastly, our emissions reduction program project. We have upwards of $1.6 billion- $1.7 billion of investment opportunity there on the Transco system in 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. 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. Just to remind people, the ownership there. Blue Racer, by the way, is no longer an entity. It'll now be Blue Racer. Midstream Holdings. Midstream Holdings. Thank you. Now that is owned effectively 50% by Williams and 50% by First Reserve. The parties that got out were primarily driven, a consortium by EnCap Flatrock Midstream. That group has been an investor in that for a long time, along with some of the management from Caiman II. Obviously, they had held onto that much longer than a typical private equity shop likes to. We worked with them to liquidate them at the appropriate time. We think we bought it right and at the right time. Particularly given the large amount of synergies that we have available to extract from that business. 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 take advantage of those, and it's been hard to not, but we've been patient, and I think our patience paid off when we were able to pick that up at a very attractive value. That's kind of how I would offer that. 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. It was a pretty complicated structure. Not only did we get it that we thought was a really good value, but We were the majority owner of Caiman, 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. 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 65% Williams, 35% CPPIB, and you have Blue Racer, which is now 50% Williams and 50% First Reserve. It's a much cleaner landscape for us to try to work on just creating value and optimizing value. Got it. Thanks for the color, 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? Yeah. Micheal, you want to take that? I would say normally our team does put some hurricane impact in there, and it's usually between $5 million and $10 million of EBITDA impact based on what a non-hurricane year would look like. It's not a huge reduction that we would typically see there on a normal year that we build into our forecast. I think I alluded to it a minute ago, I think when Christine was asking questions. Of that $49- impact we had in 2020 versus 2019, we've got all but about $10 million of that reversing itself in 2021. We still held $10 million of even maybe a little bit more than normal outsized negative into 2021 as well. The $49 was comparison to 2019. That's right. Yeah. Yeah. That's helpful. Appreciate it, John. Just thinking about where your commodity exposure lies in the G&P businesses, could you maybe just give a quick high level of maybe where the most POP lies versus keep whole, where we should think about those exposures regionally, just at a high level? We have very little, I'll just start it off with it, compared to the way the business used to be structured, we just have very little, and it's getting harder and harder to see, frankly. The areas that we do have the most exposure are keep whole, primarily keep whole agreement in our Opal area. We do have some exposure in the Gulf Coast as well. You'll see that listed as Southwest Wyoming. When I say Opal, I think in our EBITDA breakout, I think it shows it as Southwest Wyoming. That's the majority of that exposure. Again, though, we do have some margin in places like our Discovery asset, in the deepwater Gulf of Mexico. 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. Yeah. One of the other benefits of Wamsutter, we have a small amount in Wamsutter, but we will actually modernize those contracts to be fee-based as part of our cleanup of the Wamsutter basin. We'll further reduce a little bit our existing POP and keep whole contracts. I might just add, 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, they're exposed to gas prices above that. Similarly, in Laurel Mountain Midstream, those contracts basically are base level, they have exposure to gas prices above that. We do have some contracts that have direct gas price exposure in them, and Barnett and Laurel Mountain are the two areas that really have those. Very helpful. Thank you guys very much. Our next question comes from Derek Walker with Bank of America. Your line is now open. Hey, thanks, guys. I know we're over the hour here, 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 you to that? I know your guidance is 4.25, how do you think about some of the key drivers to getting you to that 4.2 in 2021? 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 2021 and our EBITDA. That's the simple way for us and probably, I would say the most profitable. As well, 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. Those are the two kind of easy ways to get there, I would say. Obviously, the EBITDA upside is the one that probably has the clearest line of sight too. Got it. Maybe just a quick one. 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 E&Ps versus private E&Ps? In what areas are you seeing some of those big differences, if any? Yeah. I've noticed that a lot of analysts are starting to pick up on that. Clearly, the public markets have been sour about spending on anything. I think the private markets have been seeing the opportunity and taking advantage of that pullback. We certainly are seeing that Haynesville is the poster child for that for sure, where there's so much private capital that's going to work there. 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 Marcellus. It's an easy place to go in a fairly de-risked manner. That's what's attracting, as Chad mentioned, that's also what's attracting a lot of capital to our opportunity there in Haynesville. 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 forward strip, which is what a lot of the private parties are doing, is what we're seeing. It's a fairly de-risked model, and they're just looking around the various basins for opportunities to do that. 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, Holt. Your line is now open. Morning. Just wanted to follow- up on some of the comments today around volumes. It sounded like for G&P, the guidance assumes something close to maintenance in the Northeast. Is that a fair characterization? Then just any high-level comments on what you're looking for in the West would be appreciated. Mike, you can take this. Yeah, I'd say on the gathering side, we are looking at most likely maintenance type activities on the gathering side. On the processing side, it's highly dependent upon the producer in the basin in the Northeast, just to be clear. There are some upsides and downsides. 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 CAFB3 there, which should be online next month. Our fractionation facilities, as said earlier, are at capacity level as well. We're seeing a lot of activity continuing in West Virginia, Ohio, Southwest Bay 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, EQT's taking that production over. We have an MVC, so it really doesn't have a meaningful revenue impact to us. That volume's declining there, and so that's muting maybe a little bit of the volume growth you otherwise would've seen in the Northeast, especially around Marcellus South. 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. Once we have that capacity built, we get that business back. That's not obvious sometimes, that we don't process everything we gather, and we don't gather everything we process. Those two numbers don't go hand in hand necessarily. On the west, where we're seeing the least activity is the Eagle Ford, which has MVC protection. Though you might see some additional volume decline, it's MVC protected in the Eagle Ford. We should see activity increasing in Haynesville. The majority of our west beyond Eagle Ford is gas-directed activity. With a relatively robust gas price, we should see good activity on the gas side of that. I'd say also, as it relates to the west, in 2021, you're seeing the back end of not as much production activity in the Haynesville as we'll see now with Chesapeake back recapitalized and new producers in the South Mansfield that we're working with. In the Wamsutter the same is happening in the Wamsutter. BP wasn't really active, nor was Marathon, obviously, because they were in bankruptcy. We're not going to see that in 2021, but in 2022, I think you'll see those volumes start to turn back around. Great. Appreciate that detail. Just a final one from me. I know you all have highlighted a couple of times how you'll be either near or at the long-term leverage target to exit this year. As you look forward, can you just update us on where you stand on capital allocation, whether that be further debt reduction, looking at a buyback authorization or supplementing maybe existing backlog with some renewables investments? Appreciate it. Yeah, I would just say that question obviously is something that we've been saying for quite some time will be coming to us, and I think as we get to the end of this year, obviously. Make no mistake about it, the first thing, and we've been very clear on this, is debt reduction is the first place to go with that. Once we get beyond that, things like 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. Those are the things that would be in competition for that further capital allocation as we get into that year. 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 base. For us, the cost of capital, it just hasn't met that return hurdle internally. In the past, it really hadn't been thought of as an opportunity. As we think about the emission reduction project, that's a very sizable capital investment opportunity that we'll make a decision on that versus other alternatives from a cost of capital standpoint. I think that's the best color I can give you on that at this point. Great. Thank you. 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 in G&A in 2021 over 2020, up, down, flattish? Just trying to look for a little direction. 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. 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 right now based on where our filing activity looks. Yeah, John is going to take the first part of your question. Yeah. On operating cost, and I am 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 cost in each of our segments and you compare 2019 to 2020, you will see a number of a $223 million reduction in operating expense. I want to be clear on that. 2019 had incremental expenses because we did a voluntary severance program and we are cutting costs. 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 in 2020 expenses. I'm dragging you through all that to say that $223 million reduction in expenses on a normalized, adjusted EBITDA basis is only $103 million reduction in expenses between 2019 and 2020. That includes an $11 million increase in operating taxes, ad valorem taxes. We saved about $114 million between 2019 and 2020. We think about 70% of that'll stick going into 2021, 30% of that'll revert. We'll see costs go up about $30 million, just due to operating costs, kind of us not retaining all that savings. Operating taxes probably go up another $20 million-$25 million. You're looking at probably $50 million of total expense increases in 2021. Great job. We're retaining 70% of our cost savings. Got it. Thank you. Thank you. Super helpful. I'll follow- up with your team offline. Much appreciated, guys. Okay, thank you all. 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 2021 and as well give us some upside here for 2021. Thank you for your interest and stay safe and healthy.