Good day everyone and welcome to The Williams Fourth Quarter and Full Year 2020 Earnings Conference Call. Today’s call 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 a presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Chandler, will speak to this morning. Also joining us on the call today are Michael Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development. In our presentation materials, you'll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in our presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. These reconciliation schedules appear at the back of the day's presentation materials. So with that, I'll turn it over to Alan Armstrong.

Great, and thanks Danilo and thank you all for joining us today. We're pleased to share the results of a very strong fourth quarter, rounding out a year of record business performance for Williams that yet again, illustrates the stability and predictability of our business. So starting here with Slide 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 four-year period. And that also during the same period, we dramatically improved our credit metrics through our asset sell 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 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. In all of these steady improvements and accomplishments build offers as 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 showed 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…

Thanks, Alan. As a very high-level summary for the quarter, our cost reduction efforts, new Transco projects brought into service, incredibly strong results out of our Northeast G&P segment, and a catch-up of minimum volume commitment EBITDA from a favorable Wamsutter/South and bankruptcy settlement helped to offset a decline in profits from deferred revenue step-downs at our Gulfstar Deepwater platform along with shut-ins from hurricane activities early during the fourth quarter of 2020. As you can see, the strong performance in our statistics on this page. In fact, we saw improvement in all of our key financial metrics both for the fourth quarter and for the full year. First, our adjusted EBITDA for the quarter was up $52 million or 4% for all of the reasons I just mentioned. The same played out on our year-to-date results. Adjusted EBITDA year-to-date was up $90 million or 2%. However, I think it's interesting to point out that if you adjust for non-cash to deferred revenue step-downs at our Gulfstar platform and at our Barnett gathering system, both of which were known and expected, as well as a few other smaller non-cash items our year-to-date adjusted EBITDA without these non-cash comparability items is actually up 4%. Again, much like it was during the fourth quarter. We'll discuss EBITDA variances in more depth in a moment. Adjusted EPS for the quarter increased 29% largely due to increased EBITDA and reduced income taxes where during the fourth quarter of 2019 there was a larger than normal state tax adjustment and also to a certain extent lesser interest expense this year. Our year-to-date EPS is also up 11%, again due to increased EBITDA, lower allocations of income to non-controlling interest owners and again to a lesser extent due to lower interest expense. This quarter representing a…

Okay. Well, thanks, John. And now, we're going to turn to our 2021 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 2020 in this plan due in part to upstream transactions that have the potential to drive incremental cash flows across our midstream assets in 2021 and beyond, plus an emerging gas storage imbalance caused by the recent higher demand that will likely we put a call on gas-directed drilling here in 2021 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 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 the 2.5% increase in the dividend announced earlier in the year, we are still maintaining similar coverage on our dividend whether we're looking at 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 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,…

[Operator Instructions] Our first question comes from Jeremy Tonet with JPMorgan Securities. Your line is now open.

Just want to touch based on the CapEx outlook, as you talked about it there, the $1 billion to $1.2 billion, 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 acquisitions in the Wamsutter, what that is exactly, that would be very helpful? Thanks.

You bet, Jeremy thank you. Well first of all, I would say we - in our base business, we have about $900 million of capital in what would be our normal base business. It is a little bit lower than what we've had historically. And that is about - half of that is in TGOM. So, that includes [indiscernible], it includes building out Leidy South, kind of the final dollars on Southeastern Trail’s and clean-up and so forth on Southeastern Trail’s 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 two-thirds of that is in the Northeast both finishing up projects, as well as getting some new project 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 2022, 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 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 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…

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, not more than $150 million to $160 million for that acreage. Then we have very little EBITDA on our guidance for that, because we're not sure exactly what kind of partnership structure we'll have if somebody else just buy a part of that acreage where we partner and we'll see EBITDA uplift. So, there's a lot of big upside I think that we can see out of that.

Yes, and one thing, and this is Chad to note, one of the reasons why I think we were uniquely positioned to step-in in this transitional role in Wamsutter and BP asset, the Southend asset are checkerboard of acreage in Wamsutter. And so, we were uniquely positioned to acquire those properties put them together as one continuous package and then move that, that asset to producer that can now develop it to its full potential. It was really locked in a situation where we couldn't have a producer get the full potential out of that acreage because of the checkerboard nature of Wamsutter. So, we're able to clean that up and now we're going to focus on moving that, that now contiguous position to a producer that can fully develop it - 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, not really expecting any kind of creep over the course of the year from what you guys can see. Is that fair to take away 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. And I'll tell you our project execution teams have really been knocking it out of the park in terms of managing cost very tightly even, 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 two key points there. We are free cash flow positive in 2021. So we'll generate more than enough cash to cover our dividends and capital and it allow us to de-leverage 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 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, but that's kind of what we believe kind of run rate to be our 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 - yes 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 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 detail that we're seeing there on the Deepwater.

Good morning, Jeremy. We are seeing continued permitting activity coming from the current administration. Since the executive order came out, we've seen four 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 just under 30 of 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 order for the Whale project. And they're continuing to process permits. And we had our Whale permit as we rolling for pipeline already last year. And so, we're continuing to work with our producer customers out there. And as you probably know, there is 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.

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

So now that you're the operator 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. Michael, you want to take that?

There's definitely an opportunity to capture some synergies there just like we did with the UEO interim acquisition that we became the operator on that asset. We rolled that into our Northeast JV. And we are having those conversations very similar with Blue Racer where we can consolidate some of the operations up there, utilize latent capacity in either one of our systems to the benefit of the other. There's a lot of activity currently on our northeast JV systems up there where our processing is full today and our fractionation facilities are full as well. And so, we would be looking to possibly use some of the 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 synergy to there ultimately and certainly some operational synergies with the teams that are there.

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 on those assets? And any more clarity in terms of when you plan to monetize that?

This is Chad. Relatively small amount of existing production around 30 million a day kind of pre last week's poll. It’s recovering. That had dropped a bit but is 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 Southland in a second but just know that they're very active up in the Spring Ridge area where they remain the owner/operator with two rigs and we think likely go into three rigs. So, that was good to see. And in Southland field, 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 2021, and we've been out now talking to potential partners and we've seen incredibly plus interest in this asset. It is a contiguous locked-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 one to two rigs at any given time to really fill up and utilize that capacity. So, we've seen an incredible amount of interest and I think we're really confident that we're 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. But we're not waiting around on that. We move very quickly. Chad and his team move very quickly to find the right partner.

Your next question comes from Christine Cho of 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&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 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 five-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 is 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'd just got the PDP’s flowing in here for Haynesville and Wamsutter assuming a July kind of finality to finding the right owner, so we only have cash flows in here on the Wamsutter area through about July. And in the 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 the upstream side of this because we really wanted 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 the gas side. So, and then I would say the other area that we've included - we've 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 been doing a terrific job of managing. And so with that, 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 firm both in Transco and Northwest pipe, and we don't have a repeat of that really in any meaningful way in 2021. That possibility still exists. We had all that hurricane activity in 2020, and our 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 2021. And so, if that doesn't happen I think there is upside of just some additional EBITDA we just didn't put in that was left and is just conservative for hurricane activity. And then Alan pointed on the expenses. So, some of this is down.

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 Macon. 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, 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. 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 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 shrink that we had bought at first of the month, turning down our processing recoveries and then selling that fuel and shrink back into the market. And so, I would tell you that 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 system that’s just a pretty small piece of our overall percentage of the business.

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

I just had one in terms of bases 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, 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 and that's how we included. 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 we’re excited about Leidy South coming on and opening up additional capacity. That's about 580 million a day of additional takeaway capacity out of the Northeast. 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 and volume uplift - upstream of that as well.

And now to the question on shut-ins in response to price where we certainly could still see producers respond to market dynamics. But I do think 2021 is going to look different than 2020. We're coming 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 A - John acreage that will continue to represent the value of our existing infrastructure. We're going to see more LNG demand come online this year, and we're going to continue to see the need for growth and supply out of the northeast. So, I'm not sure we'll see bases 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 just kind of interesting a lot more time has been spent on the upstream assets sales and midstream asset sales, but maybe if I can ask kind of where the latest thinking is on additional midstream asset sales and whether I guess some of the impairments on assets like Rocky Mountain Midstream kind of change your thinking and evaluation about how those assets might fit with the portfolio longer term?

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, you actually have to market to market effectively. And we've given some of the sales that we've seen in the space. We've seen some lower markings on the value of assets. And that's what drives those kind of considerations. And in fact, as a result of that, it would probably drive us in the other direction because it's basically saying there's a weak market right now for 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, you know, we're in a position of getting to our leverage metrics in a pretty straightforward manner and particularly these upstream assets which 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.

So, Gabe, one thing I think that is interesting, you know, 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 and around Chesapeake, what was going to happen at Chesapeake, what was going to happen in the West in general. And I think now a lot of those questions are cleared up and you can see through our performance I think we demonstrated the resiliency through diversification not that we didn't have issues in certain basins but we had good performance in other basins and it kind of washes itself out. And so, what I would say is while the market's probably a little bit weaker, I think our demonstrated performance on the business is a little bit stronger, a little bit clearer now a year later. So, I'm not sure what all that means but I think there's still opportunity still out there. And I think we've demonstrated strong performance which should help any if we ever wanted to pursue that.

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

First question is just on how you're thinking about sustainable EBITDA growth in the current environment. You guys once again highlighted about in the current environment. You guys once again he has 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 and current CapEx level 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 for 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 revenue this last year and a little bit into 2021. 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 bill 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 and saying that that produces 2%. On the other hand, I would say I think we feel very comfortable with the 2% growth rate if we are investing $1 billion 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, Mike, we might talk about the Transco project..

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 with that backlog and it became an execution project, and Regional Energy Access will be the same once we get that filing underway and get our permitting underway. And so, you'll continue to see projects come out of our backlog and move into the execution phase over the next several years. There is 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 to 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 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 backs 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 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 is 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 Cayman 2 by the way, is no longer an entity. It'll now be Blue Racer

Midstream Holdings.

Midstream Holdings. Thank you. And so, now, that is owned effectively 50% by Williams and 50% percent 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 Cayman 2. And obviously, they had held on to that much longer than a typical private equity shop likes to. And we've worked with them to liquidate them at the appropriate time. We think we bought it right 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 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 the last investment they had and one of the funds they were wanting to get that look today.

And it was a pretty complicated structure. So not only do we get it, we got some really good value but we cleaned up. We were the majority owner who came in which was half of the owner in Blue Racer. And there were two different boards that managed the joint venture and there was a lot of governance complexity. And so, we really cleaned up that asset governance. And when you think about the two large joint ventures in that part of the system now you have our OBM system which is 65% Williams, 35% [indiscernible] and you have Blue Racer which is now 50% Williams, and 50% first reserve. It's a much cleaner landscape for us to try to work on just creating value and optimizing value.

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

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, 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. What's normally our team does put some hurricane impacts in there and it's usually between $5 million and $10 million of EBITDA impact based on what a non-hurricane year would look like. 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 if we still held $10 million of even maybe a little bit more than normal outsized negatives into 2021 as well because the $49 million was comparison to 2019.

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, could you maybe just give us a quick high level of maybe where the most POP lies versus people where we should think about those exposures regionally just at a high level?

Yes. We have very little to start 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 primarily keep all 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'd say Opal, I think our EBITDA breakout, I mean it shows you to the Southwest Wyoming. So that's the majority of that exposure. And again, though, 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 gross margin basis were down to well under 2% now so it's a really, really small amount.

Yes. And one of the benefits of Wamsutter, we have a small amount in Wamsutter, but we’ll actually modernize those contracts to be fee-based as part of our cleanup of the Wamsutter basins. So, we’ll further reduce a little bit our existing POL and keep those 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 prices above that. So, we do have some contracts that have direct gas price exposure and the Barnett and Laurel Mountain are the two areas that really have those.

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

I know we're over the hour here, so just two quick ones for me. Alan I think in your former remarks you talked about line of sight on the leverage side with potential to have that $1.2 billion target achieved in 2021. Can you just talk about some of the drivers that could get you to that? I know that your guidance is 4.25, but how are thinking about some of the drivers that could get you to that 4.2 in 2021?

Yes. Well, I would say there is really two areas there. One is, obviously, the obvious and when I talked with Christine earlier about some of the upsides drivers for 2021 and our EBITDA, obviously, that's the simple way for us and probably, I would say that 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-party. So, those are the two kind of easy ways to get there, I would say. And obviously, the EBITDA upside is one that probably has a clearest line of sight to.

Got it, and then maybe just a quick one? Just on the - are you seeing much - I know there’s 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 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. 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 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 de-risk 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 current - forward strip which is what a lot of the private parties are doing is what we're seeing. So it's a fairly de-risk 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 & Holt. Your line is now open.

So, just wanted to follow-up on some of the comments there 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, we’ll take that?

Yes, fairly gathering side. We are looking at most likely maintenance-type activities on the gathering side. But on the processing side - it's highly dependent on the producer and 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 DXB 3 there. It should be online next month. And our fractionation facility 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 [indiscernible] 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 pullback, EQT is taken that production over. We have an NBC so it really doesn't have a meaningful revenue impact to us, but they - no that volume is declining there. And so, that's muting maybe a little bit of the volume growth you otherwise never seen in Northeast especially around Marcellus South.

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

And the West where we're seeing the least activity in the Eagle Ford which has NBC protection so though you might see some additional volume decline and NBC protected in the Eagle Ford. And we should see activity though increasing in the Haynesville and those gas-directed - the majority of our West beyond Eagle Ford is gas-directed activity and - with a relatively robust gas price. And 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 the Haynesville as we've seen now with Chesapeake back recapitalized and new producers in the South Mansfield that we're working with. And on the Wamsutter, the same is happening in the Wamsutter, BP wasn't really active nor with Southland obviously, because they're in bankruptcy. And so, we're not going to see that in 2021, but in 2022 I think you'll see those volumes start to turn back around.

And appreciate that detail and just a final one from 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 projects 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 some very sizable capital investment opportunity that will make a decision on that versus other alternatives from a cost of capital standpoint. So, I think that's the best color I can give you on that at this point.

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

Thank you for taking my questions. One easy one which is OpEx and G&A in 2021 over 2020, 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, Mike, why don’t you take both of those, if you don’t mind?

Yes, on Regional Energy Access, we have publicly stated in our pre-filing it was $760 million a day project. I think by the time we filed 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 we’re filing activity looks…

So yes, John is going to take the first part of your question.

Yes, on operating cost and I'll drag at these 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 $223 million reduction in operating expense. But I want to be clear on that. 2019 had incremental expenses because we did a voluntary severance program and we're cutting costs. So 2019 costs were elevated, 2020 costs were low because we changed the benefit’s program around with the days off and anyway, resulted in $40 million benefit to 2020 expenses. I’m dragging through all that to say that $223 million reduction and expenses on a normalized adjusted EBITDA basis is only $100 million reduction, $103 million reduction in expenses between 2019 and 2020. And that includes an $11 million increase in property - in operating taxes, add-on taxes. And so, we saved about $114 million between 2019 and 2020. We think about 70% of that will stick going into 2021, so 30% of that will revert. And so, we'll see cost go up by about $30 million just due to operating cost kind of - that’s not retaining all that savings. And then operating taxes probably go up another $20 million to $25 million. So, you're looking at probably $50 million of total expense increases in 2021. So a great job, we're retaining 70% of our cost savings that we got in 2020.

So, now I'll 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 and beyond 2021 and as well give us some upside here for 2021. So, thank you for your interest and stay safe and healthy.

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