Good day, everyone, and welcome to the Williams 4th Quarter and Full Year 2020 Earnings Conference Call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. Danilo Giovanni, Vice President of Investor Relations. Please go ahead.
Thanks, Lindsay, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong and our Chief Financial Officer, John Chandler, will speak to this morning. Also joining us on the call today are Michael Dunn, our Chief Operating Officer Lane Wilson, our General Counsel and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward looking statements.
This disclaimer is important and integral to our remarks, and you should review it. Also included in the presentation materials are non GAAP measures that we reconcile to generally accepted accounting principles. These reconciliation schedules appear in 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 Q4 rounding out a year of record business performance for Williams that yet again illustrates the stability and predictability of our business. So starting here with Slide 1, first of all, I'm thrilled to announce that our EBITDA once again exceeded the midpoint of our original guidance range for the 4th 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 Cayman 2 that controls Blue Racer Midstream in the Q4. 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-nineteen 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 20 19 and I'm excited to see what this organization can produce without the large number of headwinds that we navigated through this past year in 2021. Moving on here, in addition to executing on our business in 20 20, we accelerated our ESG performance. Last summer, Williams became the 1st U.
S. Midstream company to announce a climate commitment, setting an emissions reduction goal for 2,030 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 0 target by 2,000 In addition, we co led an industry effort to standardize ESG metrics with the Energy Infrastructure Council And in January, we hosted the industry's first ever ESG event specifically devoted to sharing the company's direction, goals, aspirations and tangible accomplishments related to ESG performance. In summary, in 2020, we once again demonstrated the stability and predictability of our business and importantly, we've also shown the ability to focus and execute our plan without being distracted by the challenging macro backdrop. And with that, I'll turn it over to John to go through the details.
Thanks, Alan. As a very high level summary for the quarter, our cost reduction efforts, new Transco projects brought into service, incredibly strong results out of our Northeast G and 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 Gulf Star Deepwater platform along with shut ins from hurricane activities early during the Q4 of 2020. As you can see the strong performance in our specifics on this page, in fact, we saw improvement in all of our key financial metrics, both for the Q4 and for the full year. First, our adjusted EBITDA for the quarter was up $52,000,000 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 $90,000,000 or 2%. However, I think it's interesting to point out that if you adjust for non cash to deferred revenue step down at our Gulfstar platform and at our Barnett gathering system, both of which were known and expected, as well as a few other smaller non cash items, our year to date adjusted EBITDA without these non cash comparability items is actually up 4%, again much like it was during the Q4. We'll discuss EBITDA variances in more depth in a moment. Adjusted EPS for the quarter increased 29%, largely due to increased EBITDA and reduced income taxes during the Q4 of 'nineteen 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 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 VCF except it's derived from cash from operations and is before all capital spending including before maintenance capital. Or said differently, AFFO is simply cash from operations, adjusting out working capital fluctuations and also adjusting for cash flows from or to our non controlling interest owners that shows up in the financing section of our cash flow statement. A reconciliation of this measure to cash from operations can be found in the appendix of this presentation and also in our analyst package.
You can see the AFFO grew for both the Q4 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 $42,000,000 alternative minimum tax refund we received during the quarter that was not present in the 2019 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 refund 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 Cayman 2 at Blue Racer ownership for about $160,000,000 in mid November.
A result of that acquisition, we are now at 50 percent owner of Leeracer 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 are the operator. Included in this capital spending number is also maintenance capital, which for the year was $393,000,000 about $107,000,000 less than it was in 2019. Finally, if you put our AFFO in 2020 of $3,600,000,000 up against our total capital spending including maintenance of $1,500,000,000 and our dividends of $1,900,000,000 you can see that we were free cash flow positive in 2020. This strong cash generation and capital discipline has helped move us towards our goal to improve our leverage metrics for the year. And this year, our debt to EBITDA metrics ended at 4.35 times down from 4.39 times at the end of 2019.
So now let's go to the next slide and dig in a little deeper into our EBITDA results for the quarter. Again, Williams performed very well this quarter. As you'll hear throughout each segment, cost control has been a big benefit this year. Before we dive in each segment, we believe it's important to isolate a few unusual items to make the numbers more comparable and reflective of the ongoing performance of the business. We've identified those unusual items, which are shown on this chart as non cash comparability items.
Interestingly, for the quarter, they net to only $2,000,000 and they consist primarily of 2 things. The first is a $24,000,000 reduction in non cash deferred revenue step down in our transmission in Gulf of Mexico segment on our Deepwater Gulf Star platform. As a reminder of deferred revenue, we received significant upfront cash payments several years ago from the deepwater producer, but did not recognize revenue at that time. We have been amortizing the payments we previously received in the income over the last couple of years and that amortization has been shrinking. The second unusual item is a $20,000,000 minimum volume commitment true up entry that we made in the Q4 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 1st through the 3rd quarter that we recorded in the 4th quarter. We had stopped recording those MVCs at the beginning of 2020 when Southland originally filed for bankruptcy. So with or without those non cash items, our EBITDA was up over 4%. Our transmission in Gulf of Mexico segment produced results that were $25,000,000 better than the same period last year. New transmission pipeline projects added $17,000,000 in revenues for the quarter, including the Gateway project that came into service in the Q4 of 2019, the Hillaby Phase 2 project that came into service in the Q2 of 2020 and the South Eastern Trails project that went into service during the Q4 of 20 We also did have a little over $20,000,000 in lower cost during the Q4 of 'twenty due to lower maintenance and lower labor expenses.
Offsetting these positives was $10,000,000 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 $29,000,000 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 $20,000,000 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 $9,000,000 much of which came from reduced labor costs. And then finally on the West, our West segment was down about $8,000,000 compared to 2019. But within that, revenues overall improved a little less than $10,000,000 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 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 in 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 Wamsetter. And of note, each of these basins were impacted by customer bankruptcy. And with the Southland filing 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 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 $3,000,000 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 $8,000,000 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 Q4 of 2019 that was $6,000,000 and it was something that we had received from a 3rd party compression provider. And we also had lower JV EBITDA in the Q4 of 'twenty of about 4,000,000 with most of that coming from lower OPPL profits.
And again, though, our partner on OPPL CapEx 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 4th quarter growth. The Barnett and GulfStar non cash deferred revenue step downs totaled $109,000,000 in 20 20 versus 20 19, while the net impact of commodity price fluctuations on our inventory line fill position created an $8,000,000 non cash reduction in EBITDA. So without those non cash comparability items, full year adjusted EBITDA results were actually up more like 4%, much like our 4th quarter results.
And then looking at that by segment, the transmission Gulf of Mexico assets delivered $41,000,000 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 $49,000,000 impact to our EBITDA. The Northeast is obviously a huge part of our growth this year, adding $194,000,000 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 is off by $33,000,000 largely because of the Barnett Embassy 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 and 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 'twenty one EBITDA guidance metrics.
So 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 20 20 in this plan due in part to upstream transactions that have the potential to drive incremental cash flows across our midstream assets in 'twenty one 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 'twenty one as well. So we're providing our initial EBITDA guidance range of $5,050,000,000 to $5,350,000,000 with the midpoint up 2% over last year and we'll get to EBITDA drivers here in just a second on what those specifics are, but let's go through the rest of the guidance here. Our available funds from operations or AFFO as John described, which will now replace DCF are expected to be within a range of $3,550,000,000 to $3,850,000,000 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 DCF metric or AFFO metric and this continues to really underscore the continued safety of our dividend.
Our growth CapEx of $1,000,000,000 to $1,200,000,000 is expected to remain in line with 2020 and this includes known opportunistic upstream acquisitions in the Wamsutter Basin that will be immediately accretive to both credit metrics and earnings. And notably, we still expect to generate free cash flow after CapEx and dividends, which provide us financial flexibility. And speaking of financial flexibility, we estimate ending the year with a leverage ratio of 4.25 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 'twenty one. So looking at drivers of our 'twenty one EBITDA guidance, we expect continued Northeast GMP growth from the base business and to a lesser extent the bolt on Blue Racer acquisition.
In our transmission and Gulf of Mexico business, we see Transco growth continuing to add stable EBITDA via the Southeastern Trails project that was just placed in service ahead of schedule at the end of the year and we expect late year contributions to come from our 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-nineteen 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 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 too is coming in the Haynesville, both from 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 up stream EBITDA from these existing producing reserves because we fully intend to transact during the year in a way that allows us to enjoy mid stream cash flow growth in 'twenty two and beyond as we find the right partner to fully exploit the growth available in these high value properties that we were able to pick up this past year. So we are in a very strong position now to ensure that this acreage is developed quickly and gets turned into fee based growth on our existing midstream capacity. So we really are excited about the upside potential that we've positioned ourselves for around that business. So in closing, I'll reiterate that intense focus on our natural gas based strategy has built a business that is steady and predictable with continued moderate growth, improving returns and free cash flows.
Our best in class long haul pipes are in the right place and our formidable gathering assets are in low cost basins that will be called on to meet gas demands that continue to grow. We remain bullish on natural gas because we recognize the critical role it plays and will continue to play in both our 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 the near term goal for 2,030, 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 operated above design capacity 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 or 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 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 these factors are accurately weighed and balanced, natural gas will be a very critical part of the Henderson 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-nineteen 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. And with that, I'll open it up for your questions.
Our first question comes from Jeremy Tonet with JPMorgan Securities. Your line is now open.
Hi, good morning.
Good morning, Jeremy.
Just wanted to touch base on the CapEx outlook as you talked about there, the $1,000,000,000 to $1,200,000,000 And 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? And then just if you could expand a bit more on the opportunistic upstream
I would say we in our base business, we have about $900,000,000 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 PGOM. So that includes flail, it includes building out Leidy South, kind of the final dollars on Southeastern Trails and cleanup and so forth on Southeastern Trails and some money on the front end of the REA project. So that's kind of the primary drivers there in TGOM, that's about half of that $900,000,000 And then on the balance of that, about 2 thirds of that is into Northeast, both finishing up projects as well as getting some new projects started that are driving higher margins for us in the new Northeast and some of that growth.
A lot of that investment actually will drive growth in 'twenty two 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 in front of a lot of drilling activity that's emerging there in the Haynesville. So that pretty well rounds that up. The second part of your question around the optimistic 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 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 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 Haynesville where we're already seeing Chesapeake get very focused on developing the remaining the northern part of the Haynesville that they hung on to and as well some very attractive interest coming from parties that 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 and 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 'twenty one and as well though into 'twenty two 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 1,100,000,000 dollars that included those acquisitions of that Upstream acreage in the Wamsetter. And so Alan mentioned a run rate for everything other than that of 900, maybe a little bit more than 900,000,000. So we paid less than 200,000,000 for those assets, actually significantly less than 200,000,000 dollars more than the tune of 150 to 160 for that acreage. And we have very little EBITDA in our guidance for that because we're not sure exactly what kind of partnership structure we'll have. Somebody will just buy us out of that acreage, will we partner and see EBITDA for this.
So there's a lot
of big upside I think that we can see out of that. Yes. And one thing, Jared, this is Chad. To note, one of the reasons why I think we were uniquely positioned to step in in this transitional role in lumpsutter is the BP asset in the Southland asset, our a checkerboard of acreage in longsutter. And so we were uniquely positioned to acquire those properties, put them together as one continuous package, and then move that asset to a producer that can now develop it to its full potential.
It was really locked in a situation where we couldn't have a producer get the full potential out of that acreage because of the checkerboard nature of lawns that are. 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. Thanks. And just to recap on the CapEx side, it sounds like it's a very disciplined approach there. Don't not really expecting any kind
of creep over the course
of the year from what you guys can see. Is that 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 mix that we have.
And two key points there. A, we are free cash flow positive in 'twenty one, but 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 $450,000,000 Obviously, we spent under $400,000,000 this year in 20 20. It was just artificially low just due to COVID and some issues getting some stuff done in the field.
So I wouldn't call that crude, but it is going back up from sub $400,000,000 to about $450,000,000 but that's kind of what we believe kind of that run rate to be on maintenance capital.
Got it. That's very helpful. And just one more if I could. Post the election here, it seems like there's new energy policy coming out of D. C.
And could impact federal lands production. Just wondering any thoughts you could share with us on higher level thoughts on energy policy coming out of D. C. And specifically federal lands, how you think about that? Thanks.
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 with 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. But Michael, if you would kind of share some of the details that we're seeing there in the deepwater.
Good morning, Jeremy. We are seeing for applications for permits to drill, already 60 of those have 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 on existing wells, 163 of those have been approved by the current administration and December 30 of those were on our asset footprint. So we're seeing a lot of activity for permit approvals out there. In fact, we received our gas pipeline permit after the executive order for the Whale project, and they're continuing to process permits.
And we had our Whale permit for the oil export pipeline already last year. And so we're continuing to work with our producer customers out there. And as you probably know, there's a lot of leases that they've locked up and a lot of permits that they already had in hand. And so there's a long runway of activity that will continue to occur in the Gulf of Mexico, we believe.
Got it. That's very helpful. Thank you.
Our next question comes from Praveen Satish with Wells Fargo. Your line is now open.
Thanks. Good morning. So now that you're the operator of Blu 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 Yes, there
is definitely an opportunity to capture some
synergies there. Yes, there's definitely an opportunity to capture some synergies there just like we did with the UEO M acquisition that we became the operator on that asset. We rolled that into our Northeast JV and 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 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. Thanks. 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 in both assets? And any more clarity in terms of when you plan to monetize that?
Sure. Hey, this is Chad. Relatively small amount of existing production, around 30,000,000 a day, kind of pre last week's coal. It's recovering, it dropped a bit, but it's recovering. So not a lot of existing production, around 130 existing wells.
But I will first say, we were really encouraged to see Chesapeake emerging from bankruptcy as a really healthy customer. So I'll touch on South Mainston in a second, but just know that they're very active up in the Spring Ridge area where they remain the owner operator with 2 rigs and we think likely going to 3 rigs. So that's good to see. And in South Mansfield, we do that as an additional opportunity where we have $350,000,000 to $550,000,000 a day of capacity available from a midstream perspective for development in that area. We closed on that transaction prior to 2021 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 will 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.
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 move very quickly to find the right partner.
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. So is this really driven by G and 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-twenty 21 impact? And have the producers behind the system in the Northeast started to talk to you about these plants, if that is the case?
Yes, 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 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 side to Kudis. 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 July kind of finality to finding the right owner. So we only have cash flows in here on the Wamsutter area through about July. And in the 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 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 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. 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 2021 does assume that we've got some comeback on cost that frankly the team has just been doing a terrific job of 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, so on short term perm, both on Transco and Northwest Pipe, and we don't have a repeat that really in any meaningful way in 'twenty one. 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 to be a little bit more active in 'twenty one.
And so if that doesn't happen, I think there's upside of some additional EBITDA, just some additional EBITDA we just didn't put in that was at the end, just conservative for hurricane activity. And then Alan pointed on the expenses.
So some of this is on TIGOM 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 Mid Con, Is all of your natural gas storage in Texas contracted to 3rd 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.
First of all, we actually don't have any gas storage in Texas. So the storage on Transco is at Washington, which is kind of the middle part of the state by Opelousas. And so that's where the storage facilities are. And 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 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 out either Northeast or in the Rockies, which were not directly impacted. But I would just say as well, our team did a great job of doing things like selling fuel and strength that we had bought at 1st of the month, turning down our processing recoveries and then selling that fuel and strength 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.
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 producers' forecasts 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 are saying they're going to do. And to the degree that we have a line of sight for how that's going to happen, that's how we've seen it.
And so far, they've been pretty accurate, consistently pretty accurate in the way that they've been forecasting that. They know the reserves and they know the market. I will say that obviously, site without Wybie South coming on and opening up additional capacity, that's about 580,000,000 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 together in volume uplifts upstream of that as well. And I'll to the question on shut ins in response to price, we certainly could still see producers respond to market dynamics, but I do think think 'twenty one is going to look different than 'twenty. 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 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 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 of having infrastructure to move from Appalachia to growing markets. But we'll certainly keep an eye on it. Thank you. And then maybe if I can just ask, it's kind of interesting that a lot more time has been spent on the call on upstream asset sales and midstream asset sales, but maybe if I can ask kind of where the latest thinking is on additional midstream sale, asset sales and whether I guess some of the impairments on assets like Rocky Mountain Midstream kind of Yes, I don't really think so, Gabe.
I think we were as to the RMM impairment that we took, that's 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 market to market effectively. And we've given some of the sales that we've seen in the space, we've seen some lower markings on the value of assets and that's what drives those kind of considerations. And in fact, as a result of that, it would probably drive us in the other direction because it's basically saying there's a weak market right now for 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 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 2020, it was actually in January of 2020, I think we were heavy in the middle of thinking about trying to market some of our assets in the West. And there were a lot of question marks at the time around Chesapeake, what was going to happen in Chesapeake, what was going to happen in the West in general. And I think now a lot of those questions are cleared up and you can see through our performance, I think we demonstrated the resiliency through diversification, not that we didn't have issues in certain basins, but we had good performance in other basins and it kind of washes itself out. And so what I would say is while the market is probably a little bit weaker, I think our demonstrated performance on the business is a little
bit stronger, a little bit clearer now a
year later. So not sure what all that means, but I think the opportunity is still out there. I think we've demonstrated strong performance, which should help if we ever wanted to pursue that.
Our next question comes from Spiro Dounis with Credit Suisse. Your line is now open.
Hey, good 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 $12,000,000,000 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 Michael 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 revenues 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 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 through. 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 at all time. But I would tell you that it's more complex than taking $1,000,000,000 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 $1,000,000,000 we feel very comfortable with achieving a 2% growth rate. But given some of the upsides that we've got in some of these areas, I think that probably would be kind of considered a floor from my perspective on that. So we might talk about the transfer projects.
Yes. We look at that backlog and it's really dynamic because we have a lot of projects that come into that backlog and then we execute on a lot of those projects. And Southeastern Trail is one that came out of the backlog, Leidy South came out of that backlog and became an execution project and regional energy assets will be the same once we get that filing underway, our permitting underway. So you'll continue to see projects come out of our backlog and move into the execution phase over the next several years. There's a plethora of opportunities along the Transco Corridor to take advantage of coal fired generation that's going to come offline and ultimately be converted to gas and renewables.
And I think from the activities we've seen in Texas and Oklahoma over the last week, there definitely needs to be a mixture of energy generation resources in the mix in order to diversify across fuel sources. And so I'm a true believer in that. Our company is definitely a natural gas focused company now that I'm adding in some renewable mix into the display there to take advantage of some opportunities we have. But ultimately, on the Transco system, we're going to be able to drive a lot of new capital investment there on the fact of coal fired generation going away. And then lastly, our emissions reduction program project, we have upwards of $1,600,000,000 to $1,700,000,000 of investment opportunity there on the Transco system and likely replacing a large component of our reciprocating compression to new 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 Tresco'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 Cayman 2 by the way is no longer an entity, it will now be Blue Racer Midstream Holdings. Thank you. And so now that is owned effectively 50% by Williams and 50% by First Reserve. The
parties that
got out were primarily driven a consortium by NCAP, Flat Rock, Midstream. And so that group has been an investor in that for a long time along with some of the management from Cayman 2. And obviously, they had held on to that much longer than a typical private equity shop likes to. And we worked with them to liquidate them at the appropriate time. We think we bought it right and at the right time and particularly given the large amount of synergies that we have available to extract from that business.
And so we're excited about the transaction. I can tell you we were super patient. We've been wanting to gain control of that asset and exploit the synergies between both our UEOM system and our Ohio Valley River. We've been wanting to 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 attractive value. So that's kind of how I would offer that, but I think at the end of the day it was a private equity held investment that was needing to get out because that was the last investment they had in one of their funds and they were wanting to get that And it was a pretty complicated structure.
So not only did we get it, we got some really good value, but we cleaned up it. We were the majority owner of Cayman, which was half of the owner in Blue Racer, and there were 2 different boards that managed 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 OBM system, which is 55% Williams, 35% CPPIB, and you have the ERASR, 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. Thank you.
Our next question comes from Christian Richardson with Truist Securities. Your line is now open.
Hey, good morning, guys. I appreciate all the comments on the Gulf of Mexico and around the outsized impact in 2020. I think you noted in the slides $49,000,000 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, Michael, you want to take that?
Yes, I would say normally our team does put some hurricane impacts in there and it's usually between $5,000,000 $10,000,000 of EBITDA impact based on what a non hurricane year would look like. So it's not a huge reduction that we would typically see there on a normal year that we build into our forecast.
And I think I alluded to a minute ago, I think when Christine was asking questions, we of that 49 negative impact we had in 2020 versus 2019, we've got all but about $10,000,000 of that reversing itself in 2021. So we still held $10,000,000 of even maybe a little bit more than normal outsize negative into 2021 as well.
Because the $49,000,000 was comparison to 'nineteen. That's right. That's helpful.
Appreciate it, John. And then just thinking about where your commodity exposure lies in the G and 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?
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 have very little and it's getting harder and harder to see frankly. But the areas that we do have the most exposure are primarily keep hold agreement in our Opal area and we do have some exposure in the Gulf Coast as well. So you'll see that listed as Southwest Wyoming, when I say Opal, I think in our EBITDA breakdown, it shows you the Southwest Wyoming. So that's the majority of that exposure. And again, though we do have some margin in place like our discovery asset in the deepwater Gulf of Mexico.
But I think total and plan on gross margin basis were down to well under 2% now. So it's a really, really small number. And one of the benefits of Wamsutter, we have a small amount in Wamsutter, but we actually modernize those contracts to be fee based as part of our cleanup of the Wamsutter Basin. So we further reduce a little bit our existing PUL and people contract. 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 Mid Street, 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. Barnett and Lower Mountain are the 2 areas that really have those.
Our next question comes from Derek Walker with Bank of America. Your line is now open.
Hey, thanks guys.
And I know we're over the hour here. So just two quick ones from me. Alan, I think in your formal remarks, you talked about line of sight on the leverage side with potential to have that, I think that 4.2 target achieved in 2021. Can you just talk about some of the drivers that could get into that? I know your guidance is 4.25, but how do you think about some of the drivers to get into that 4.2 in 2021?
Yes. Well, I would say there's really 2 areas there. One is obviously the obvious that when I talked with Christine earlier about some of the upsides drivers for 'twenty one or 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 one that probably had 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
and Ps versus private E
and Ps and what areas are
you seeing some of those big differences, if any? Yes, I've noticed that a lot of analysts are 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. And 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.
And it's in a contracted 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. 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 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 current forward strip, which is what a lot of 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 regard.
Our next question will be from Colton Bean with Tudor, Pickering and Holt. Your line is now open.
Good morning. So just wanted to follow-up on some of the
comments there around volumes. It sounded like for
G and 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. Michael? Yes.
I'd say on the gathering side, we are looking at most likely maintenance type activity on the gathering side. 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 TXV-three 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 the West Virginia, Ohio, Southwest PA 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, they're going up that much
in the Northeast, Laurel Mountain Midstream, Chevron pulled back, EQCP is 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 you otherwise would have seen in the Northeast, especially around Marcellus South.
And just to be clear there, it's a little bit confusing sometimes in the Southwest Marcellus and West Virginia area there because we gather some of that gas and then we spin it off to 3rd 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 gather and we don't gather everything we process. And so those two numbers don't go hand in hand necessarily. And on the West, where we're seeing the lease activity is the Eagle Ford, which has MVC protection.
So though you 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. And with a relatively robust gas price, we should see good activity on the gas side of that.
And I'd say also as it relates to the West, in 2021, you're seeing the back end not as much production activity in Haynesville as we'll see now with Chesapeake back recapitalized and new producers in the South Mansfield that we're working with. And in the Wamsut, the same is happening. The Wamsut, our BP wasn't really active nor was Falcon, obviously, because they were in bankruptcy. And so we're not going to see that in 'twenty one, but in 'twenty two I think you'll see those volumes start to turn back around.
And appreciate that detail. And just
a final one for me. I think you all 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
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 we'll make a decision on that versus other alternatives from a cost of capital standpoint. So I think that's the best color I can give you on that at this point.
Great. Thank you.
Our last question will come from Michael Lapides with Goldman Sachs. Your line is open.
Hey, guys. Thank you for taking my questions. One easy one, which is OpEx and G and A in 'twenty one over 'twenty, 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?
Yeah, Mike, why don't you take both of those?
Yeah. On Regional Energy Access, we have publicly stated in our pre filing was a $760,000,000 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 $800,000,000 $1,000,000,000 of investment and we're probably at the lower end of that right now based on where our filing activity looks. So, yes, John is going to take the first part of your question.
Yes, so on operating cost and I'm going to drag you through some numbers here real quick, but if you look in our analyst package and if you look at the operating cost in each of our segments and you compare 2019 to 2020, you'll see a number of a $223,000,000 reduction in operating expense. But I want to be clear on that. 2019 had incremental expenses because we did a voluntary severance program and we're cutting costs. So '29 costs 2019 costs were elevated. 2020 costs were low because we changed the benefits program around days off and anyway resulted in a $40,000,000 benefit to 2020 expense.
I'm dragging through all that to say that $223,000,000 reduction in expenses on a normalized adjusted EBITDA basis is only a $100,000,000 reduction, dollars 103,000,000 reduction in expenses between 2019 2020 and that includes an $11,000,000 increase in property in operating taxes, ad valorem taxes. And so we saved about $114,000,000 between 'nineteen 'twenty. We think about 70% of that will stick going into 'twenty one, so 30% of that will revert. So we'll see costs go up by about $30,000,000 just due to operating costs kind of that's not retaining all that savings. And then operating taxes probably go up another $20,000,000 to $25,000,000 So you're looking at probably $50,000,000 of total expense increases in 'twenty one.
So great job, we're retaining 70% of our cost
savings. Got it. Thank
you. Super helpful. I'll follow-up with your team offline. Much appreciated, guys.
Okay. Thank you.
We'll 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 'twenty one and as well give us some upside here for 'twenty one. So thank you for your interest and stay safe and healthy.