威廉斯 (WMB) 2020 Q4 法說會逐字稿

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, 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 the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Chandler, will speak to this morning. Also joining us on the call today are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development.

In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in the presentation materials are non-GAAP measures that 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 but yet again, illustrates the stability and predictability of our business. So starting here with Slide 1.

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 4-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 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. 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 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 '21.

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. At 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 improvements 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 noncash 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 noncash items, our year-to-date adjusted EBITDA without these noncash 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 that were due in the fourth quarter of '19. There were -- 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 noncontrolling interest owners, and again, to a lesser extent, due to lower interest expense.

This quarter, we're presenting a new cash flow metric, and we'll continue to present this going forward. The measure is available funds from operations. This measure will replace distributable cash flow and is 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 noncontrolling interest owners that shows up in the financing section of our cash flow statement.

A reconciliation of this measure of the 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 noncontrolling 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 that 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. 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 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. And this year, our debt-to-EBITDA metrics ended at 4.35x, down from 4.39x 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 noncash comparability items. Interestingly, for the quarter, they net to only $2 million, and they consist primarily of 2 things. The first is a $24 million reduction in noncash deferred revenue step down in our Transmission & Gulf of Mexico segment on our deepwater Gulfstar platform.

As a reminder, our 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 noncash 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 2 project that came into service in the second quarter of 2020 and the Southeastern Trail project that we need to service during the fourth quarter of 2020.

We also did have a little over $20 million in lower cost during the fourth quarter of '20 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 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.

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 $2 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 have been 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 rate and slightly lower volumes in the Midcontinent 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. And of note, each of these basins were impacted by a customer bankruptcy. And with the Southland filing a reemergence filing a couple of weeks ago, all those bankruptcies should be resolved soon.

Also of note, in 2 of those 3 basins where we saw a majority of our volumes decline, specifically in the Wamsutter and Eagle Ford, 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 cost 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 commitment 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 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. 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 noncash 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 noncash reduction in EBITDA.

So without those noncash 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 TGOM 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 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%, but 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.

So 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, and now we're going to turn to our '21 EBITDA guidance metric. 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 billion 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 the DCF, are expected to be within a range of $3.55 billion 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 AFFO metric, and this continues to really underscore the continued safety of our dividend.

Our growth CapEx of $1.0 billion 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 dividend, 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 '21.

So looking at drivers of our '21 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 & 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 Leidy 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 hurricane 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 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 us 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 '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 basis 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 countries and the world's pursuit of a clean energy future. Natural gas is an important component of today's fuel mix and should be prioritized as one of the most important tools to aggressively displace more carbon-intensive fuels around the world.

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 network 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 -- we did not have to curtail any services to our gas transmission customers. And in fact, operate above design capacity on our Northwest Pipeline system for a period and delivered flawlessly on a new record 3-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 the 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 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 of 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 with 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.

And with that, I'll open it up for your questions.

(Operator Instructions) Our first question comes from Jeremy Tonet with JPMorgan Securities.

Just wanted to touch base on the CapEx outlook, as you talked about there, the $1 billion to $1.2 billion. And just want 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? And then 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.

You bet, Jeremy. Thank you. Well, first of all, I would say, we -- 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. And that is -- about half of that is in TGOM. So that includes Whale. It includes building out Leidy South, kind of the final dollars on Southeastern Trails and cleanup and so forth on the Southeastern Trails and some money on the front end of the REA project. So that's kind of the primary drivers there in TGOM, that's about half of that $900 million.

And then 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 '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 Haynesville area as we're really going to be having to work hard to keep out [front of a lot] the drilling activity that's emerging 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 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 -- the northern part of the Haynesville (inaudible) 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.

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 if, 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 flow.

So 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 '21 and as well though into '22 and beyond as we attract the capital to develop those reserves. So 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, 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 Upstream acreage in the Wamsutter. And so Alan mentioned a run rate for everything other than that of $900 million, 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 to the tune of 150 to 160-point for that acreage. Then we have very little EBITDA in our guidance for that because we're not sure exactly what kind of partnership structure we'll have. Or somebody will just buy us out of that acreage, will we partner and so EBITDA uplift. So there's a lot of big upside, I think, that we can see out of that.

Yes. And one thing, Gary, this is Chad. To note, one of the reasons why we were uniquely positioned to step in, in this transitional role in Wamsutter is the [BPS] at the Southern asset are a checkerboard of acreage in Wamsutter. And so we were uniquely positioned to acquire this property, 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 could have a producer get the full potential out of that acreage because of the checkerboard nature of Wamsutter. 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. And just to recap on the CapEx side, it 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?

Yes. 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, and then we wound up, even including the Blue Racer acquisition coming in under that.

So yes, we -- 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 the 2 key points there. A, we are free cash flow positive in '21. But we'll generate more than enough cash to cover our dividends and capital and that 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 million.

Obviously, we've spent under $400 million this year in 2020. It was just artificially low just due to COVID and some issues getting some step down in the field. So I wouldn't call that creep. It is going back up from sub-$400 million to about $450 million (sic, see slide 5, "$500 million"), but that's kind of what we believe kind of run rate would 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.

Yes. I would just say, I'm going to have -- Mike will 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. But we've seen maybe a different story than has been -- that you're hearing in the media in terms of the actual actions going on out there. And most of the acreage is ready to develop it. Micheal, if you would kind of share some of the details that we're seeing there in the deepwater.

Jeremy, we are seeing continued permitting activity coming from current administration. Since the executive work 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 delivering to us. And then when you talk about permits for modifications such as workovers, things of that nature of existing wells, 163 of those have been approved. The current administration in the -- [December 30], those are on our asset footprint.

So we're seeing a lot of activity for permit approvals out there. And in fact, we received our gas pipeline permit. After the executive orders with 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 have in hand. And so there's a long runway of activity that will continue to occur in the Gulf of Mexico, we believe.

Our next question comes from Praneeth Satish with Wells Fargo.

So 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?

Yes. Sure. Micheal, do you want to take that?

Sure. Yes, 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've rolled that into our Northeast JV. And we are having those conversations pretty similar with Blue Racer where we can consolidate some of the operations up there, utilize linked 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 Blue Racer 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 synergies there ultimately and certainly some operational synergies with the teams that are there.

Great. And then 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? And any more clarity in terms of when you plan to monetize that?

Yes, sure. This is Chad. Relatively small amount of existing production, around 30 million a day kind of pre last week's call. It's recovering, had dropped a bit but is recovering. So not a lot of existing production, around 130 existing wells.

But I would 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 Springridge area, where they remain the owner-operator with 2 rigs and we can likely go into 3 rigs. So that was good to see.

In South Mansfield, we view that as an additional opportunity where we have 350 million 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 Haynesville and Mid-Bossier 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 we'll dedicate 1 to 2 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 going to find a great partner there and unlock the potential of that asset.

Yes. And I would just add to that, we are well into that process in terms of finding the right partner on that. And we've been very encouraged by the strong level of interest from a number of parties. So -- but we're not waiting around on that. We've moved very quickly, Chad, just to -- moved very quickly to find the right partner.

Our next question comes from Christine Cho with Barclays.

If I could maybe just talk about the high end of the EBITDA range that you gave for 2021. It's -- 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.

So 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. And have the producers behind the system in the Northeast started to talk to you about these plans, if that is the case?

Yes. Thank you. Well, Christine, you're -- I mean, you're targeting right on the correct issue there. We really developed that plan before we've seen this recent call. And 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 5-year average.

And meanwhile, production, we really haven't seen the activity in production to stabilize that decline in storage. And the places that are going to be able to respond to that quickly are going to be Haynesville 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 Haynesville and Wamsutter, assuming a July kind of finality to finding the right owners. So we only have cash flows in here on the Wamsutter area through about July.

And 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. So I wouldn't be the first to admit that we've been very conservative on our -- on the Upstream side of this because we really want to leave ourselves full flexibility, and we didn't -- 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 the upsides are probably mostly related to volumes in the Northeast. But I would also say we remain pretty conservative in the forecast that we have for the deepwater 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. We did a great job in 2020 on cost and our '21 does assume that we've got some come back on costs that, frankly, the team has just been doing a terrific job in managing. And so that's another area of opportunity for us as well.

And just a couple of things maybe to play on that a little bit with Alan, on Transco, we were successful in 2020 selling short-term [Perm] Both on Transco 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.

We do expect that it could a little bit more active in '21. And so if that doesn't happen, I think there's upside of some additional EBITDA, just some additional EBITDA we didn't put in that was left and that's just conservative for hurricane activity and then 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 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? 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.

Yes. Thanks, Christine. First of all, we actually don't have any gas storage in Texas. So our -- the storage on Transco is at Washington, which is kind of the middle part of the state by Opelousas. And so that's where the storage facilities are and that -- so there really wasn't a whole lot of impact there. And obviously, Transco is designed to flow from that area, designed to flow to the north and east, not back in Texas.

In terms of the impact to us, I would say 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 out -- is either Northeast or in the Rockies, which were not directly impacted. The -- but I would just say as well, our team did a great job of doing things like selling fuel [in trains] that we had bought at first of the month, turning down our processing recoveries and then selling that fuel in trains back into the market.

And so 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. 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.

Our next question comes from Gabriel Moreen with Mizuho.

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 and obviously, they take that into consideration. And if the prices come up, they'll turn some volumes on. And -- but 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, but 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 should say you'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 see it. And so far, they've been 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 Leidy 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 Leidy South on the projects 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 uplifts -- upstream of that as well.

And Al, to the question on shut-ins in response to price, we certainly could still see producers respond to market dynamics. But I do think '21 is going to look different than '20. We're coming into -- 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 basis that we'll continue to represent the value of our existing infrastructure. We're going to see some more LNG demand to come online this year, and we're going to continue to see the need for growth of 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 having infrastructure to move -- broaden Appalachia to growing markets, but we'll certainly keep an eye on it.

And then maybe if I can just ask kind of -- interesting that a lot more time has been spent on the call, 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 [benefit] the portfolio longer term?

Yes. I don't really think so, Gabe. I think we were -- as to the RMM impairment that we took, that's been an equity-level investment. So 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. But in those, we actually have [to mark it] 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 GDP 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 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. And so right now, I can 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, 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 with 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. And 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 is probably a little bit weaker, I think our demonstrated performance front of 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 there's still opportunity still out there, and I think we've demonstrated a strong performance, which should help any -- if we ever wanted to pursue that.

Our next question comes from Spiro Dounis with Crédit Suisse.

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, 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.

Yes. I'm going to have Micheal speak to that backlog on projects. But 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 '21. So I think you have to be careful about making those kind of broad assumptions.

So for instance, when the deepwater 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 nice surges of margin based on very high incremental return opportunities as they come to us.

And 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 a decline that's working against it all the time. But I would tell you that it's more complex than taking $1 billion in saying that, that produces 2%.

On the other thing, and 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. But given some of the upside 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. So we might talk about potential problems on this.

Yes. We look at that backlog, and it's really dynamic because we have a lot of projects that come into that backlog and that we execute on a lot of those projects. And 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 their permitting underway.

So you'll continue to see projects come out of our backlog and move it 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 off-line 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 of 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. But 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.

And then lastly, our emissions reduction program projects, we have upwards of $1.6 billion 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?

Yes. So just to remind people the ownership there. Blue Racer is -- and Caiman II, by the way, is no longer an entity. It will now be Blue Racer Midstream Holdings. 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 EnCap Flatrock Midstream.

And so that group has been an investor in that for a long time along with some of the management from Caiman II. 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 take advantage of those. And it's been hard to not, but we've been patient, and I think our patience paid off and we're able to pick that up at a very attractive value.

So that's kind of high off of that. But I think at the end of the day, it was a private equity held investment that was needing to get out. That was the last investment they had in one of their funds, and they were wanting to get that lifted.

And it was a pretty complicated structure. So not only did we get it -- we thought it was a really good value, but we cleaned up. We were the majority owner of Caiman, which was -- half of the owner, and Blue Racer, and there were 2 different boards that manage the joint venture. There was a lot of governance complexity, and so we really cleaned up that asset governance.

And when you think about the 2 large joint ventures in that part of the system now, you have our OEM system, which is 65% Williams, 35% CPPIB and you have the Racer, which is 50% Williams and 50% First Reserve with a much cleaner landscape for us to try to work on, just creating value and optimizing value.

Our next question comes from Tristan Richardson with Truist Securities.

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?

Yes. Mike, do you want to take that?

Yes. 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 nonhurricane year would look like. So it's not a huge reduction that we would typically see there on a normal year that we built into our forecast.

And I think I alluded to a minute ago, I think when Christine was asking questions, we -- of that $49 million 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 million as comparison...

To '19, that's right.

Yes. That's helpful. Appreciate it, John. And then just thinking about where your commodity exposure lies in the G&P businesses, can 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?

Yes. We have very little. I'll just start it off with it. Compared to the way the business used to be structured, 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 keep-whole, primarily, keep-whole agreements 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 breakout, I think it shows you Southwest Wyoming. So that's the majority of that exposure. And again, we do have some margin in places like our Discovery asset in the deepwater Gulf of Mexico. But I think the total and plan on a gross margin basis, we're down to well under 2% now. So it's a really, really small number.

Yes. And one of the other benefits of Wamsutter, we have a small amount in Wamsutter, but we will relax the way we modernize those contracts to be fee based as part of our cleanup of the Wamsutter basin. So we'll further reduce a little bit our existing POL and keep-whole 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 Laurel Mountain are the 2 areas that really have those.

Our next question comes from Derek Walker with Bank of America.

North over the hour here. So just 2 quick ones for 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, but how do you think about some of the drivers to getting to that 4.2 in 2021?

Yes. Well, I would say there's really 2 areas there. One is obviously the obvious -- when I talked to Christine earlier about some of the upside drivers for '21 and our EBITDA, obviously, that's the simple way for us and probably, I would say, the most profitable, but 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. So those are the 2 kind of easy ways to get there, I would say. And obviously, the EBITDA upside is the one that probably have 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 ex kind of bankruptcies from public E&Ps versus private E&Ps? And what areas are you seeing some of those big differences, if any?

Yes. I've noticed that a lot of analysts were starting to pick up on that. And clearly, the public markets are just -- have 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 Haynesville is the poster child for that, for sure, where there's so much private capital that's going to work there.

But it's an attractive place because you don't have a lot of the basis risk that you have to manage in the long-haul capacity risk that you have to manage coming out of the Marcellus. So it's an easy place to go in, in a fairly derisked 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 the Haynesville.

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 -- the current forward strip, which is what a lot of the private parties are doing is what we're seeing. So it's a fairly derisked model and they're just looking around the various basins for opportunities to do that. But clearly, in our line of sight, Haynesville is the area that's getting the most attention in that (inaudible).

Our next question will be from Colton Bean with Tudor, Pickering and Holt.

So 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? And then just any high-level comments on what you're looking for in the West would be appreciated.

Mike?

Yes. On the gathering side, we are looking at most likely maintenance-type activity on the gathering side. But on the processing side -- and it's highly dependent upon 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 (inaudible) there. It should be online next month. And our fractionation facilities, as I said earlier, are at capacity level as well. So we're seeing a lot of activity continuing in West Virginia, [Whale], Southwest (inaudible) 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, but they -- so that volume is declining there. And so that's muting maybe a little bit of the volume growth we 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 -- the 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 gathered. And we don't gather everything in process. And so those 2 numbers don't go hand in hand necessarily.

And on the West, where we're seeing the lease activity is the Eagle Ford, which has MVC protection. So we might see some additional volume decline. It's MVC protected in the Eagle Ford, and we should see activity increasing in Haynesville and those gas directed -- the majority of our West beyond Eagle Ford is gas directed activity. With 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'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. And in the Wamsutter, the same is happening in the Wamsutter. BP wasn't really active nor was Southland, obviously, because of their own bankruptcy. And so we're not going to see that in '21. But '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, looking at a buyback authorization or supplementing the existing backlog with some renewables investments? Appreciate it.

Yes. I would just say the -- 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 this end of this year, obviously, that will be -- but 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. 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 base. 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 to capital standpoint. So I think that's the best color I can give you on that at this point.

Our next question will come from Michael Lapides with Goldman Sachs.

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?

Yes, Micheal, why don't you take both of those.

Yes. On Regional Energy Access, we have publicly stated in our pre-filing it 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 right now based on what our filing activity looks. So yes, John is going to take the first part of your question.

Yes. So on operating cost, and I want 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 of -- 2019 costs were elevated. 2020 costs were low because we've changed the benefits program around days off. And anyway, it resulted in a $40 million benefit to 2020 expense. I'm dragging you 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 -- in operating taxes, (inaudible) 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 revert. So we'll see costs go up by about $30 million just due to operating costs kind of not -- that's not retaining all that savings. And then operating taxes, probably for another $20 million to $25 million. So you're looking at probably $50 million of total expense increases in '21. So a great job. We're retaining 70% of our cost savings.

I will now turn the call over to Alan Armstrong for closing comments.

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.