Good day, everyone, and welcome to the Williams Investor Update 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. Brett Krieg, Head of Investor Relations. Brett, please go ahead.
Thank you. Good afternoon, and thank you, everyone, for joining our call today. A few moments ago, we posted the presentation This information is important, and you should review it. In addition to that information, please note that we are having this discussion with you today to provide an indication of the current state of our business, financial position and operations. We remind you that everything we say is currently is current only as of today, especially in light of the uncertainty surrounding the length and severity of the recent COVID-nineteen or coronavirus outbreak.
The evolving nature of the impact of this crisis across our business and the volatility that the energy industry is experiencing as well as the markets. We are not planning to update the information we tell you today or provide any additional information until our Q1 earnings call. Also during the call, we will reference non GAAP measures that we reconcile to generally accepted accounting principles. These reconciliation schedules appear at the back of today's presentation materials. Leading the call today is our President and CEO, Alan Armstrong And he is joined by our CFO, John Chandler and our Chief Operating Officer, Michael Dunn.
So I'll turn it over to Alan now for his remarks.
Great. Thank you, Brett, and thanks everybody for joining us this afternoon. We really did want to take the opportunity to explain what's going on within our business. And I think it's really interesting time for us because as you know, we really have built this business to be very predictable and stable and durable through the cycles. And so we think it's a real opportunity for Williams to distinguish itself in this market with the stability of our business.
And so I'll start here on the first slide just laying out for you the fundamentals behind our business. And first of all, reminding you that our business, as we said all along, is really built around natural gas demand. And so the natural gas supply and demand driven market fundamentals that we have always while people have certainly worried the low gas prices, we've consistently reminded folks that that has built demand and will continue to build demand both because natural gas is low cost and because it's clean. And those fundamentals even with the price route that we've seen on oil, those fundamentals still exist. And so we remain very confident and we also would remind you that one of the reasons that we have invested so heavily and focused so heavily behind natural gas is we did realize that it was resting on a fundamental market and was not supported by things that can change in a moment's notice the way we've seen on the oil price recently.
So longer term, the oil price shock, we believe will be positive for the natural gas basins we serve and we'll talk a little bit more about that. But I would just remind you that really over the last year, there's been a lot of pressure downward on Williams with people concerned about the growth from the Northeast gas volumes in the face of rising associated gas coming out of places like the Permian and the Bakken. And so I would just tell you, I think that that issue has certainly been shaken out of the market and we think on a longer term basis points capital back towards dry natural gas. And so we think our strategy and sticking to that will pay off for us here. And then finally, I would just say on the fundamentals here that the natural gas demand currently and we'll show some data here in a moment.
Currently, we have and that is up to present, we have not seen any negative impact in the business associated with the throughput on our systems. And in fact, we're currently operating above historical norms on a heating degree day basis on adjusted and in fact on an absolute basis even with the lower heating degree day. So the demand destruction that some might be expecting and we're certainly not sitting here forecasting what will happen with a slower economy either domestically or global. We are not trying to forecast that, But we are here to tell you that today the volumes are holding up very firmly and in fact are operating above normal for this time of year. I also would say that the relative to COVID-nineteen, we certainly recognize that a global recession ultimately would impact natural gas demand.
But we also think that the supply side, what we're most interested in is where that supply comes from to meet that demand. We think we're extremely well positioned with the associated gas reduction that we're likely to see with a continued downturn, if that is what we see. So next on first just to remind you of how our business are holding up natural gas transmission. We are fully contracted across all of our 3 major pipelines, Transco, Northwest Pipeline and Gulfstream. So obviously no change to that business.
Even if there was a volumetric layoff there, we that's fully contracted. And so no changes whatsoever to the cash flows coming out of that business. John will go through kind of a picture of that customer base here in a moment, but that remains I also remind you we have several large growth projects going on along the systems and those remain well supported and the contract standing behind of those remain as valid as they were before. And so that growth in our business remains very well supported. As well on the our natural gas gathering and processing, on the onshore basis, about 85% of our onshore gas gathering and processing is focused on gas directed drilling basins and rather than oil.
And so the balance is on oil directed basins. But I also would remind you of the diversity of both our customer base as well as supply areas where we're gathering from over 15 different basins that we currently serve. And so that diversity keeps us well positioned and keeps us focused on natural gas demand because we do know that we're going to get our share of that natural gas demand across those. In addition, a lot of concerns obviously continue to exist around bankruptcies of our counterpart, particularly on the producing side. And I would just remind you that we are very careful about our credit on our long haul pipelines and we feel extremely well supported by the physical nature of the service that we provide to our customers on the gathering side where we gather back to the wellhead and therefore, we remain very confident in our ability to continue to get paid because we are the only way for those products to get to market.
And I also would remind you that the way those contracts work, the MVCs where we have them are directly tied and they are integral to the contract. And so for somebody to get out of the MVC, they would also have to reject the contract in full. And that in most cases, that is just not feasible alternative at all because of the cost associated with having to rebuild these very large and complicated systems that we utilize together our customers' gas. Our deepwater transportation business is supported mostly by majors and a long cycle perspective, and we have not seen any change in those projects. We've certainly been in touch with our customers on that front and that is full bore ahead.
I'll remind you the capital we're spending this year on the shale well prospect is reimbursable by Shell and they've told us to proceed on that. So if they did back up for some reason on that, we would be fully reimbursed on that capital. But as we sit here today, the teams are working full speed ahead on those projects. And then finally on the our adjusted EBITDA, we do expect to come in towards the lower end of our range based on 2 primary issues. One and probably most important is just to remind you that our NGL margin or NGLs are about 2% of our adjusted EBITDA here for 2020 as we've laid out.
And the obviously that will be dramatically impacted if prices stay this low. So even though that's not a large number, our range is actually fairly tight against the business. And so that will drive us towards the lower end of our range as we sit here today. The second driver is more associated with growth and particularly around the DJ Basin, where we were expecting continued growth in that basin. And while we haven't seen obviously haven't seen anything shift on that yet, we fully expect to see producer pullback in those oil directed basins like the DJ.
The Eagle Ford is the forecast that we have is fully protected by MVCs and so we don't expect any big in our estimate for the year is right down on top of that MVC. So we don't expect any big shift there for the Eagle Ford. But really those 2 primary issues, lower growth in the DJ along with much lower NGL prices, we think will put us towards the lower end of our current EBITDA guidance range. So that's the bad news side of this lower pricing environment. The good news is we are able we've been able to scrape back quite a bit of capital, reminding you that we had already dramatically lowered it at the time of Analyst Day associated with lower gas prices, which drive quite a bit of our capital in the producing areas.
So we had already turned that back quite a bit, but we are going to be able to pull that in a little bit lower. And so as a result of that, we do expect to still maintain the positive free cash flow to the tune of around $100,000,000 as we forecasted at the Analyst Day. And so we're really excited to be able to continue to maintain that position and the strong financial position that puts us in and obviously the flexibility that that gives us at this point in time. So really not too big a shifts going on within the guidance. I would tell you that NGL prices have really come down hard over the last week or 2 weeks.
And particularly though in the last week, they've really taken out. So we are not expecting much out of NGL margins for the balance of the year when we tell you that we expect to be in the lower end of our guidance range on EBITDA. And move on to the next slide here. And this is a really interesting picture. I hope you'll find it interesting.
And this is right out of our raw data for our transmission systems. And so I'll start with that over on the right. And you can see there in blue, that's our actual throughput volumes on our transmission system. I want to remind you that none of that has anything to do with how we get paid on these systems because capacity is fully sold out. But it obviously has implications for how much gas demand there is continuing and the changes that might be occurring with the changes in people's work behaviors.
And as you can see, the 2020 volume is actually above the 2019 volumes and that's even with a 32% year over year reduction in heating degree days on the Transco system, which is obviously the bulk of these volumes. And so pretty interesting picture here to see that even with lower rescom load associated with just lower heating degree days and very significant lower heating degree days, we still are running above last year's numbers on total throughput on the system. On the slide on the left there, the left hand side of the slide just shows that on a lower forty eight basis And you can see there the same thing is being recognized across all of the Lower forty eight where natural gas demand is actually higher than the 3 year average and has actually ticked up here in the last week. So not really a picture of demand disruption that we can identify going on within the natural gas side at this point. So moving on, now I'm just going to get into a couple of slides here that talk about what has changed and what we're exposed to as Williams versus the broader midstream industry.
And so you look on the next slide here on 3, you can see natural gas prices have actually picked up a little bit from March 5 through 23, so about a 1% pickup. Importantly, 2021 picking up a little bit and we have seen some renewed interest in drilling in the Haynesville and people being able to hedge up against this forward curve in the Haynesville as a result of that. So we have seen some degree of positive impact from that curve starting to shift upward on the back end on gas. Secondly, you can see on the crude oil, you can see the very sharp decline there moving down 36% on the 4 12 month strip here. And so dramatic change on oil, while very little has changed on the gas side.
We moved on to Slide 4 here. This is just kind of going down some of the various drivers within the midstream industry and reminding you where Williams is positioned against these various risks. And I'll just remind you that our business, we do not have the supply and logistics business that a lot of our peers have in the space. Our business is long term fixed prices for the most part. And so we're not seeing the movements in the rates on our business associated with our across our long haul pipeline.
So for instance, on WTI Crude, it's down 36%, neither in our G and P business or in our gas transmission business do we have any exposure to crude oil price there. On basis differentials, those have narrowed 50% between Midland to Houston, which is pretty impressive for the short amount of time that's being measured here. And again, we have no business that is driven by that basis differential. NGL prices, we've talked about, we have 2% exposure though. Those are down 39% And thank goodness we are limited in our exposure to that at this point.
And then on Henry Hub Natural Gas, we do have a little very small amount of length in some of our gathering contracts that get priced up against that. It's very small and it's covered in the short position that we have on our NGL marketing spread. So no net exposure there to natural gas one way or the other on a direct basis and certainly no exposure within our transmission business. On the Waha to Henry Hub on the natural gas basis, no exposure there. We also have no exposure across any of the other major bases and that just because that's not the way we run our transmission business.
And so you can see though the Waha to Henry Hub, which has been a pretty healthy source of income across the midstream sector. We are not exposed to that here. On the volume impact side, natural gas demand, as we have said many, many times, we are very exposed to natural gas demand, not in our transmission business in the short term at all, as I've mentioned, but in our GMP business because whatever gets pulled through on the demand side is going to come. We're going to get our share of that on the G and P side. And so 38% of our EBITDA is coming from gas directed drilling.
And another way of thinking about that is of our onshore gathering, 85% of our onshore gathering is coming from the gas directed drilling. You can see on the gas rig count, and this is I would admit this is not a very good indicator because it's just a week to week, but we're down 1 rig from prior week to this latest Baker Hughes count. And on the oil side, we were down 19 rigs. I think a lot of you all probably track that pretty closely and you know that that number is going to on the oil side is going to continue to expand pretty rapidly. And so we do have 7% of our 2019 EBITDA came from oil directed drilling.
So in other words, associated gas gathering in the Eagle Ford, the DJ, the Permian and the Mid Continent. And so we would expect that to be impacted except for the MVC that we have in Eagle Ford, which we are forecasted sitting right on top of. So very well protected on that front, but we are exposed on the gas demand side and we would expect that actually to turn net positive to us as associated gas starts to slow down and more of the gas demand has to be met from the areas that we are the more dominant gatherer in. On the gas transmission side of that exposure, on natural gas demand, I'll just remind you, we do have $3,200,000,000 in projects underway. As I mentioned earlier, those are well supported and remain supported.
We would see if we did see demand for some reason fall off pretty dramatically over a long period of time, obviously that would affect new projects and our ability to contract for new growth expansion on Transco. But right now, we're not expecting that. That's very long cycle business that gets done and people have to forecast out 4 or 5 years at a time. So but that is we wouldn't try to say that in the long term it's not exposed to natural gas demand, but certainly here within the horizon of our forecast, we won't be impacted by it within our transmission business. Moving on to Slide 5 here.
This just shows you a nice picture of in 2019 where different sources of EBITDA come from and you can see about 44% coming from those long haul pipelines, 9% coming out of the Deepwater Gulf of of Mexico. And remember, the Deepwater Gulf of Mexico, even though that is serving producers primarily, those are really majors. And we're not dependent on the ups and downs of drilling rigs moving in and out. It's a very long cycle business and not any near term shifts expected in that business associated with this current downturn just because the decisions made there are much longer cycle. And then about as I mentioned earlier, about 38% of our EBITDA from G and P, but 85% of our total onshore gathering and processing coming from the G and P business and 7% from the oil directed.
And then you can see that small 2% that is NGL Services. So that's around our Conway businesses, Conway Frac and Storage Business as well as our marketing around those assets. So that is a nice picture, and I think you can understand why we feel fairly insulated given our exposure to the gas directed side of this picture. With that, I'm going to turn it over to John to talk about the quality of our customers across our business and then to talk about our maturity schedule behind that. So John?
Thanks, Alan.
So if you go to Page 6 of the slide deck, we have been getting a fair number of questions about our transmission system and customers on our transmission system and we think that's a good question and that's something that the analysts and investors should focus on. We're proud to say if you look at our system, our system is a demand pull system backed in large part by utilities, power plants, LNG facilities, industrial plants, and it's really not a producer push system. So that's the first point we'd make on this slide on the pie chart on the left. If you look at aggregate of our customers by type, 81% comes from utilities, LNG, industrial and power consumers. Only 7% comes from producers.
And I would say a big piece of that sliver is Cabot, and Cabot is serving end user demand. So I wouldn't view them as traditional producer just trying to find a market. So very stable and reliable customer base that's supporting the sperm committed capacity on our regulated pipelines. Another interesting way of looking at it on the right side of the slide is the credit quality of these customers. And as you can imagine, because it is heavily backed by utilities, you can see 90% of our customers on our transmission systems are investment grade, 1% high yield and 9% not rated.
So again, either way you look at it from the kind of customer to the kind of credit quality, we have a highly reliable customer base on our transmission systems that against firm committed capacity not subject to really volume fluctuation. Now if you go to the next slide on Page 7, another question we're getting fairly significantly or fairly frequently is about our liquidity. Coming into this year, I'll tell you, we had around $300,000,000 in cash as we exited 2019, and we had a $4,500,000,000 untapped revolver that extends into 2023. We spent a fair amount of time talking to the market about our desire to refinance maturities as they came due this year and that we would be patient with that as we looked for opportunities potentially liquidate interest in assets if that market were available. Clearly, that market has slowed down given that a lot of investors we think would have relied on high yield Term Loan B type markets to back leverage an investment in one of our assets.
Just to be clear, in our JVs, we don't allow leverage in the JVs we formed in the Northeast and around the DJ Basin. But for back leverage purposes, we think investor classes, we're looking to those markets. So as we think as we look forward, we did take the $1,500,000,000 that matured in March onto our revolver. We do have another $600,000,000 that comes due in November. In both occasions, because of the significance of our revolver, we have very significant liquidity.
And I'll come back to the point that we have on the right side of this slide and as we talk to you coming into this year, we are covering all of our CapEx and all of our dividends with cash from operations. And so we didn't have the need for any additional leverage to cover our capital or our dividends. So we have various significant liquidity to carry that maturity on a revolver until we find a better market. So we'll watch for that market to improve, the term loan our long term financing markets to improve and rates that we would find attractive, but we've got significant capacity on our revolver and significant liquidity. On the free cash flow side, I finished with this point and Alan talked about this in the opening comment.
As we've looked across our business in this kind of new environment, again, clearly our NGL marketing activity, which is only 2% of our EBITDA is exposed and we've actually had 2 or 3 months of decent profits around that. So even in looking at that, we do think there could be some slide in some of the EBITDA around our NGL marketing activity. And we do have a slight amount of EBITDA exposed in our oil directed basins. But again, if you add that up, about 7% of our EBITDA comes from oil related basins and again 5% of that is the Eagle Ford on the back of an MVC. So there's really not a lot of rest there.
But if you look at those two areas and think about the EBITDA risk, we do think we could come in towards the lower end of our EBITDA range. We don't believe we need to change our guidance, but we could come in on the lower end of that. But again to the good news, as we look through our capital, we think we can also reduce that and it will not change our ability to be free cash flow positive for the year. So with that, I turn the call back over to Alan.
Yes. Thanks, John. So I'll just wrap here real quickly and we'll turn it over for Q and A. First of all, I would just say our business is steady and predictable. We think that's going to really shine through in this environment.
We think in terms of the 2 major things that have changed since our last earnings call really is obviously the oil and NGL price route that's gone. And we think really on net long term that is more positive for us as we become more reliant on the gas directed basins that we serve. So we actually think that's a net positive for us even though it will be painful obviously for the market to push through. I also think even and who knows how long the price war and the current environment will exist around just the decisions of the OPEC plus and their decisions to produce. But I would say, I think long term, the impact is already very significant not fully aware of the risk associated with oil cycles.
And so I think that impact has been had here regardless of how much longer the price route remains. On COVID-nineteen as the other significant impact, certainly not clear to us right now what the long term impact of that is going to be to natural gas demand here at home or around the world. Hopefully that is going to be short term. In terms of its impact, again, we're not seeing that today, but we fully expect if the economy slows down as a result, which we fully would expect that certainly to some degree to occur. It's not clear to us how much that will affect natural gas demand.
And so we're not really ready to call that and try to predict what that will amount to for our business. We can only report what we know today, which is that we haven't seen it impacting the throughput on our systems today. So with that, we appreciate your interest in the company and appreciate you joining us this afternoon. And I'll turn it over for questions.
Our first question comes from Shneur Gershuni with UBS. Your line is open.
Hi. Good afternoon, everyone. And guys, thank you for having this call in these difficult circumstances. I was wondering maybe to start off, you've talked about the fact that you expect to have some flexibility on your CapEx for this year. I was wondering if you can talk about operational costs as well also.
I know that you've had some successful efforts in the Northeast in the past. Do you expect to be able to take some more costs out of your business and reduce your the operational costs as well also?
I'm going to Shneur, thank you. I'm going to ask Michael to who's done with who's with us today, I'm going to ask him to take that question.
Hi, Shneur. Good afternoon. We as you recall, we talked about this, I believe, in our earnings call. We took a lot of cost out of the business last year coming into 2020, knowing that we did have some challenges and headwinds. And so we took the opportunity to find ways to reduce those costs.
We took about $75,000,000 out of our run rate OpEx at that time and we are continuing to find ways to take more operating expense out of the business. We are going through that process now and we are finding some of the opportunities to eliminate and or defer those into next year, but we still see opportunities there to continue to improve upon that.
Great. And maybe for a follow-up question. If we run into a scenario where there's 0 rigs running and no completion activity in your West segment, what kind of decline rates should we be thinking about? And is that contemplated in being able to hit the bottom end of your guidance range?
Yes, Shneur. I don't know that we can nail that down for you. I would tell you obviously there's not a lot of rigs. The thing I think people need to remember is much like Michael just answered, the gas side of the industry has already been dealing with these extreme low prices. And so the gas price impact on the gas directed basins, we pretty well already felt that I think and have been feeling that.
I think the oil directed basins, I think very likely to see a lot of rigs pulled out of there obviously. And I think so if we think about that against our oil directed basins, which would be Eagle Ford, Permian, a little bit of Mid Continent and the DJ. Again, 5% or sorry, 5% of that 7% is supported by MVC and our current volume there is and our current estimate for volume is right down on top of that MDC. So that locks up a big chunk of that. The balance of that in the DJ, we're 50% of the DJ.
It's not a very big number for us at all, but it is important for us in terms of growth. And I think we would have expected that to grow somewhere in the neighborhood 30% this year off of a very small number last year in terms of EBITDA. So that we likely will lose some of that growth this year from the DJ. So that's probably about the mode we didn't have. I don't think we expected any rigs running in the Mid Continent to speak of against that basin.
And the Permian is just very, very small. I think our total Permian is somewhere around $25,000,000 of EBITDA. So it's very small to us. So that's probably the best answer I can give you just off the top of my head there. I think we'd have to look for the oil directed basins.
And because we have that MVC in the Eagle Ford that shores up quite a bit of it.
Right. Perfect. I do have more questions, then I'll go back in the queue and re queue. Thank you very much. Appreciate this today and stay safe.
Thank you. You too.
Your next question comes from Jeremy Tonet with JPMorgan. Your line is open.
Hi, good afternoon. Thanks for taking my question. Just want to start off if you could kind of refresh us on thoughts of capital allocation philosophy at this point. Given that Williams stands at a 12% yield today, just wondering do you think any of that capital could be better deployed towards paying down debt if that would help out the equity there or even buying back stock or anything opportunistic in the market? It just seems like it's a unique time out there and just wondering if you could refresh us on how you think about these things?
Yes, Jeremy, good question. Well, first of all, just caveat this that decisions of capital allocation to that degree are obviously a Board level decision. And so I'll remind you that and we take that as a Board, we take that very seriously and weigh a lot of different factors. We certainly believe that having a reliable dividend is extremely important to the value of our company. I think it's very hard to read through the current environment and assess anything about what shareholders think about value.
And I think we are going to keep our eye out far on the horizon as this kind of business demands. And so I don't think you would see us reacting to destroy investor confidence for some short term opportunity. So I would just say that to start with. But I don't disagree that there's an obvious question to be raised there and that question will be raised with the Board and answered. But I would tell you from my own personal perspective, maintaining our dividend is extremely important.
And the good news is we are extremely well positioned to do that because of the free cash flow positive situation that we're in and expect to be able to remain in. So I think the on the credit and on a debt side, I think the quality of these cash flows are kind of going to come screaming through this period and give the rating agency even more confidence in our business model than they might have had historically. And so I actually think this could be a net positive for us from a rating agency. So anyway, that's I know that's not a firm answer. You're obviously not going to get one, but I will tell you that we do understand the extreme importance of maintaining and holding our dividend.
And I don't see anything that would force us off of that at this point in time.
Understood. Thanks for that. And then maybe you could comment
a little bit on, I
think there was a recent news with the shareholder rights plan and just wondering if that was something that was kind of in the works for a while, if that's something that just kind of evolved because of the current situation or any color you could share there would be helpful. Thanks.
This is John Chandler. Jeremy, it actually it hasn't been in the direct response to the incredible decline that we've seen in our share price. And in fact, if you look as of the end of last week, I was looking at the S and P 500 declines just in general, and I think it's down 25% year to date. Energy is down 57% year to date. So if you stack that in the share price performance relative to the discussion we just had about the quality of our cash flows and how it's durable and it's holding in there, it just it's evidence of the risk here for someone to step in with the share price that has been significantly impaired just due to broad market reaction without actually discerning between quality of cash flows.
And we felt our Board felt like that was inappropriate to provide to not protect our long term investors against people who may try to come in just with the short term interest of trying to drive value somehow that isn't a long term interest for the company. So it was in direct response to the reaction that we saw in our share price. And but just to be clear, we did not adopt that rice plan in response to any specific threat.
That's helpful. I'll stop there. Thank you.
Thank you.
Your next question comes from Tristan Richardson with SunTrust. Your line is open.
Hey, good afternoon guys. Really appreciate the state of the union. Alan, you mentioned CapEx kind of trending towards the low end of the range. And it seems like that you suggested that that primarily comes out of the West. But are there specific projects where you've got a lot of discretion there or we think of Bluestem as a sizable piece of the budget this year.
Just any added detail on types of projects that you have full discretion that can either slow down or make adjustments to the schedule?
Yes. First of all, just starting with the bulk of it, which is our transmission projects, Those are full bore ahead and in fact the permitting actually with the exception of Nessie, permitting has actually gone a little better than we originally expected on those projects. And so that's stable and well supported projects and don't really see much shift on that. I would tell you our teams are doing a great job of managing costs and timeline on our projects and continue to over perform on that front. And so some of this is just cost coming out of our projects.
In the West, obviously the DJ Basin and the Eagle Ford are areas where we had capital tied up for well connects there. And so we would expect some pullback on that West. And then up in the Northeast, most of that is just working with producers to find lower cost ways serving their needs up there from what we originally projected up there. So it's I would say it's kind of across the board in terms of where the costs are coming out as to Bluestem. We certainly are enjoying really tight cost controls by team on that and that's allowing us to scrape some out of that, but don't really expect to pull that project.
In come 2023, our volumes that are today on ONEOK all come back to us. And so we've got to have that project completed. And so the most we could do would to delay that and that really doesn't make a lot of sense for us frankly just because we're so far along on the project. So I don't know, Michael, if you'd add any color to that.
Yes. I think Alan discovered that pretty well. We our team is doing a great job digging through all of the projects and finding ones that we can either defer or actually eliminate some of our maintenance capital. We've found ways to do things differently or better and we've been able to shake some of those out as well. So we've probably got close to $175,000,000 to $200,000,000 of opportunity to take out of the capital forecast that we had put in place last fall anticipation of where we were going with the business.
But as Alan said, a lot of the work is underway on our transmission side. The shop Eastern Trail project is under construction and going very well. And our Leidy South project permitting is ahead of schedule and we anticipate starting construction on that late in the year or early next year. So I think we're moving along very nicely on the transmission side for our major projects that are underway.
Very helpful. Thank you guys very much.
Thank you.
Your next question comes from Gabe Moreen with Mizuho. Your line is open.
Hi, good afternoon, everyone. Thanks for the call. Clearly, you've laid out sort of your target on the balance sheet improvement side of things, but I'm wondering kind of on the flip side, at what level of debt to EBITDA you feel you really need to defend on the balance sheet and how that translates into defending, I guess, the investment grade credit rating?
I mean, we've got I will tell you this, we've had a fair number of questions about interactions with ratings agencies and we've been in conversations not a normal course. This is usually when we go in for kind of our usual conversations. So we've been in contact over the last 2 or 3 weeks. We feel like we've got we're Baa3 with Moody's. We feel like we've got a lot of capacity there and we're stable there.
And so we believe there's very little jeopardy on that front. On Ditch, we're BBB- with a positive outlook and they've extended that through 2, 3 month cycles. We were coming to the end of the second 3 month cycle and did have a conversation with them last week. And I think, I don't want to put words in their mouth, but I think they're just they want to continue to see what happens on the producer activity front, but they didn't take that positive off at least as of last week. S and P were BBB flat, stable with S and P, they did do some ratings actions with a lot of the producers.
We wondered if that could be through to us, but there's no indication at this point that that's going to happen. And I think they're in a wait and see mode. So I would say, as it relates to investment grade in general, S and P is way above a BBB flat. And Moody's, we feel like we have a lot of capacity. So it's hard for me to imagine that we'd run into a situation where we would have to do something to take care of a problem relative to our investment grade rating.
I would think on rating from a rating agency calculation standpoint, those ratings, just to give you a number, I think on our GAAP numbers, we'd have to approach a 5 times type leverage number on our account before. And even then, I think if you look at other Canadian pipeline companies, they have leveraged higher levels than that and their investment grade rated. So I feel like we've got a lot of capacity.
Thanks, John. And then also I'm wondering if you're starting to hearing from any of your contracting crews on your projects about working limitations in terms of needing to space out crews. Is that something you're anticipating and might have an impact on how that might be managed?
Yes, this is Michael. We've been pretty proactive with our contractors and the nature of the pipeline business is such that they are pretty spread out anyway. So but we're making sure that like our large gatherings in the morning don't occur where they would typically have a safety discussion. They're doing that remotely and with distance. And so we're making sure that we're following all the proper guidelines from a distancing standpoint.
Our contractors are putting in and have already put in separate trailers, separate facilities for their crews and segregating their crews even amongst our facility sites where they're working and so that they're not working in large groups and not interacting as much with our operations teams, especially where we're working real hard to keep our operations team segregated from contractors coming into the facilities. And we're doing a really good job of that. We segregated on the operations side our control room. So we have multiple desks within certain control rooms and we've segregated those desks out where our controllers are not working in the same rooms with each other as well. And just really dispersing our employees across the footprint so that we can maintain continuity of operations.
But so far, we've seen nothing from our contractors that indicates that they're slowing down work in regard to the coronavirus situation.
Thanks for the color, Michael. Appreciate
it. Your next question comes from Craig Shere with Tuohy Brothers. Your line is open.
Thanks for hosting the call. This is very helpful. On the Eagle Ford with the MVC, I believe that's mostly with Chesapeake. Can you remind us how long that remains stable in terms of the volumes? And can you maybe dig into anything further in terms of color if the assets there were to change hands on your confidence that the MVC stands?
Great. Thank you, Craig. First of all, I don't think we have laid out the specifics of the length of that MVC, but it is long term. I think we have laid out the term of that contract, which is through 30 2, but I would sorry, 2,032, but I would just tell you that the MVC is pretty long dated within that contract. In terms of the confidence on that and just to remind you the producers behind that, the working interest behind that is Cenook.
So the Chinese National Oil Company has a pretty large working interest back behind those wells. I think it's somewhere around 30% to 35%, I think, of the working interest is held by them. But when we talk about the Chesapeake revenue number, we don't include their backstop of that because we actually get paid by Chesapeake on that. So when we talk about now roughly 6% of our revenues come from Chesapeake, we don't include that working interest support behind that. So with that backdrop, I would just say relative to the Eagle Ford MVC security, there just is not a feasible way to duplicate the systems that we have that go back to these wellheads that are fairly low volume production sites because they're oil based production.
So it's very low volume, which makes it extremely expensive to replicate that gathering system and the treating because most of that gas is very sour. And so it makes it very, very difficult to replicate that system and it would be very difficult to do anything with the gas other than to take it into our treater there. So we feel very confident. I'll just remind you the way those contracts work that MVC that's embedded is embedded within the agreement. And therefore, you would have to if you were the successor to Chesapeake, you would have to decide that you were going to reject the entire contract to get rid of the MVC and then you would be left without a way to get your without a way to produce that production out there because you wouldn't have a way of getting rid of that gas.
So we think it'd be very, very difficult to reject that contract and the MVC is fully embedded. There isn't any precedence for anybody being able to split up a contract like that and separate the MVC from the Gathering Agreement. So we feel very confident. And we also obviously have the agreements, have the mineral lease dedicated to them and run with the land. So we feel very strong about the contractual position.
Obviously, the Kingfisher Midstream and Alta Mesa deal proved up our position on that ruling recently. And so we remain very confident in our ability to continue to get paid on those gatherings.
Great. And my last question, people are worried not so much about 2020 as 2021 if these very depressed liquids prices sustain. In terms of the and I'm not looking for specific guidance, but as you look out a couple of years, knowing all the ins and outs and your mostly gas business, do you think in a worst case scenario that really hurts some of the liquids focused peers that you could roughly be treading water on EBITDA? Or how much downside ultimately do you think we have a couple of years out?
Well, Craig, you've followed us and I read your writing on it. So I know you appreciate the balance of natural gas demand and how we're positioned. And I think if you think that we have pulled a lot of capital that will ever go back into the oil basin within the kind of timeframe that you're talking about, if that capital has been pulled out, natural gas from that's not supported by oil and much less supported by NGLs is going to have to stand up to the charge for natural gas demand. I'd say that suggesting that natural gas demand will remain healthy and supported. But I think one thing is clear is that the balance between dry gas and associated gas in meeting that demand has made a major shift in a positive direction towards dry natural gas.
And there is not anybody in the business that's better positioned up against dry natural gas than we are between Susquehanna County, Bradford County, Haynesville and the Utica. There is not anybody that's got those basins that are covered than we do. And so we feel pretty good about the longer term impact and the positive inflection that we'll get in those basins associated with capital being pulled out of the oil directed base.
Great. Thank you.
Our last question comes from Tim Schnee with Citi. Your line is open.
Hey, thank you so much. I had a question about your Slide 5, and I think that's a helpful slide. If we kind of look at it and we say, okay, 53% is that blue bottom is kind of locked in EBITDA. Can you help us understand the rest? Let's ignore the marketing business for a second, that 2%.
Out of that 45%, how much of that EBITDA is kind of locked in, if you want to call it that way, by minimum volume commitments versus just pure fee based or other?
Yes. John, we've or Grace, we've shown that on earlier slides. So I don't have that slide handy right here.
Okay. And then my follow-up to that would sorry, go ahead.
I was just going to
remind you, Tim, this is Brett, that we do have a past slide we published that shows the gross margin broken out along those lines. And it's a little bit less than half of the G and P business on the gross margin side has some form of volume protection associated with it, whether that's MVC or cost of service or capacity payments on the NGL business. And then it's a little bit more than half. I can follow-up or we can on that slide later.
Yes, sure. That would be great. And the other question I have, given that roughly 10% of the EBITDA comes from the Gulf of Mexico, do you have a sense as to because it hasn't happened in a long time, at what oil price Gulf of Mexico production would actually start to shut in and you see some sort of a volume impact on that?
Tim, I've been in the deepwater for about as long as it's been around. And I don't recall a time where we saw oil get shut in for lack of cash margin. The problem is promote on the shelf, we saw some of that. So some of the really low volume stuff that got abandoned along the shelf as prices dip into the 20s. But in these big deepwater fields, there's so much of that fixed.
They can't walk off and abandon those platforms from an operational perspective. So said another way, they can't just decide they're going to walk off and unmanned those platforms, Coast Guard rigs. So there's a lot of fixed costs already sitting on that that would be almost very, very difficult to abandon. And so the actual variable cost to that is really low. So I don't have a crisp answer for you on that, but I can say that the deepwater as opposed to what was on the shelf 15 years ago, that deepwater, I can't really imagine it seems like it'd be some of the very last oil that would actually shut in.
Okay, got it. That's helpful. And then Brett, I'll follow-up with you offline on that slide. Thank you very much, guys.
Thank you.
Ladies and gentlemen, we have reached the end of the allotted time for the question and answer session. I will turn the call back over to the presenters for closing remarks.
Okay. Well, thank you all very much for joining us. Appreciate your continued interest in the company and we're really pleased to be presenting how the business is doing. And we want each of you to stay healthy and take care of yourselves. And thanks for joining us on the call today.
This concludes today's conference call. You may now disconnect.