Categories Earnings Call Transcripts, Energy

Williams Companies Inc (NYSE: WMB) Q1 2020 Earnings Call Transcript

WMB Earnings Call - Final Transcript

Williams Companies Inc (WMB) Q1 2020 earnings call dated May 05, 2020

Corporate Participants:

Brett Krieg — Head of Investor Relations

Alan S. Armstrong — President And Chief Executive Officer

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

John D. Chandler — Senior Vice President, Chief Financial Officer

Chad J. Zamarin — Senior Vice President, Corporate Strategic Development

Analysts:

Jeremy Tonet — JPMorgan — Analyst

Colton Bean — Tudor, Pickering, Holt — Analyst

Gabe Moreen — Mizuho — Analyst

Alex Kania — Wolfe Research — Analyst

Tristan Richardson — SunTrust — Analyst

Shneur Gershuni — UBS — Analyst

Praneeth Satish — Wells Fargo — Analyst

Presentation:

Operator

Good day, everyone, and welcome to the Williams’ First Quarter 2020 Earnings Conference Call. [Operator Instructions]

At this time, for opening remarks and introductions, I would like to turn the call over to Mr. Brett Krieg, Head of Investor Relations. Please go ahead.

Brett Krieg — Head of Investor Relations

Thanks, Simon. Good morning, everyone. Thank you for joining us and for your interest in the Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong, will speak to you momentarily. Joining us on the call today are our Chief Operating Officer, Micheal Dunn; our CFO, John Chandler; our General Counsel, Lane Wilson; and our Senior Vice President of Corporate Strategic Development, Chad Zamarin.

In our presentation materials, you’ll find the 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, and these reconciliation schedules appear at the back of today’s presentation materials. So with that, I’ll turn it over to Alan Armstrong.

Alan S. Armstrong — President And Chief Executive Officer

Great. Well, thanks, Brett, and good morning, everyone. Thanks for joining us today as we go through our first quarter 2020 financial performance. While the world around us has changed dramatically, some things have remained remarkably stable. And we should not take for granted the sacrifices and dedication required to keep the most essential of services available to us. So I’d like to start by thanking the frontline employees of Williams, who have continued to operate our critical natural gas infrastructure during the Coronavirus pandemic. We often take our warm and well-lit homes for granted, but it took great dedication, extra effort and resourcefulness to keep our most basic energy needs available during these disruptive times.

Thankfully, we have always maintained robust plans to ensure business continuity, and we’ve been able to successfully execute on these plans while staying aligned with federal and state guidelines to keep our employees healthy and safe. I’m glad to report we have not missed a beat, and this is a testament to the efforts of our employees across the country. Of course, the other big related news story that we are closely monitoring is the collapse in oil prices and the impact this is having on our upstream customers. With that said, let’s get to the business at hand and talk about our strong 1Q 20 performance. On slide one, we provided a clear view of our first quarter 2020 financial performance relative to 1Q of 2019. And as you can see, this was a really good quarter.

We continue to enjoy steady growth across our key measures despite the impact of much lower commodity margins and deferred revenue recognition step down. From the top of the table, you’ll see we continued a long trend of year-over-year growth in cash flow from operations. Our adjusted EBITDA also increased 4%. And while this is attractive growth, this growth rate would be 8% if you pull back some of the noncash items related to step-downs in deferred revenue amortization and the impact of declining prices on our carried NGL inventories. I’ll discuss the key business drivers and unique issues affecting adjusted EBITDA in more detail on the next slide, but DCF was up an impressive 10% on a year-over-year basis. And of course, all this continues to drive impressive growth in our per share metrics, adjusted EPS and DCF as well.

We also were very pleased to continue growing our strong coverage ratio by 5% on top of the 5.3% dividend growth that we established earlier this year. Our 1.78 times coverage ratio means DCF exceeded dividends paid by $376 million. Another strong data point driving our cash flow performance in the first quarter was a 45% or nearly $200 million reduction in growth capital expenditures. Taking all of these items into account, the strong DCF, the growth in the dividend and disciplined growth capital spending, Williams generated real free cash flow of $144 million this quarter alone. A lot of different versions of free cash flow out there, but this is after all of our cash expenses, the dividend and our growth capital expenditures as well.

These financial results further reduced our debt-to-adjusted EBITDA ratio to 4.36 times for the first quarter. As a reminder, this ratio stood at 4.8 times at the end of 2018. And since then, we have moved this important ratio nearly 75% of the way to our longer-term goal of the 4.2 times leverage that we’ve reminded you of several times. We are pleased with this performance, and we have intentionally built our business to be resilient through a variety of market cycles, and that strategy is certainly helping us navigate today’s choppy waters. Our healthy dividend coverage and strong balance sheet leading into 2020 have put us in a very stable financial position and well positioned to navigate the changes that we are experiencing across the industry.

So let’s move to slide two and discuss the main business drivers of our first quarter 2020 adjusted EBITDA results. Before we dive into the drivers for this quarter, I want to remind you that we have transitioned our business segment disclosures to align with our internal reorganization that took effect in January. Our transmission in Gulf of Mexico operating area now includes all of our regulated natural gas transmission pipelines, of course, Transco, Northwest and Gulfstream and our deepwater Gulf of Mexico assets that deliver supplies into Transco and Gulfstream. We will continue to evaluate and disclose the performance of the Northeast G&P and West operating areas separately, but those segments are now integrated from a senior leadership and overhead standpoint and that change allows us to improve efficiency, alignment and cost savings across all of our onshore gathering and processing business.

So now looking at the chart on slide two, we compare adjusted EBITDA in the first quarter of 2020 to the same period in 2019. I’ll quickly remind you that 1Q 2019 represented a great period of growth for us, which was just following the Atlantic Sunrise startup and the associated Northeast gathering volume growth that we said. So a nice strong comp to compare ourselves to. But before we get into the discussion of the key business drivers, I also want to talk about some of the things that affected the EBITDA number that I think obscured the underlying business performance.

First is the impact of the lower deferred revenue recognition in the Barnett and our Gulfstar deepwater platform. These are both noncash items totaling $21 million and are not reflective of the ongoing cash flow from these assets. We also saw a $24 million of impact this quarter related to decreases in inventory values. This was due to decline in the value of NGL linefill and write-downs of NGL commodities and storage. While NGL price exposure is clearly part of our business, these charges are driven by directional movement of market prices. And for this sort of charge to occur recur, we would have to see a continual drop in NGL prices from the already very low prices that we mark these inventories at on March 31. So of course, this does not include the actual NGLs that we produced in the equity sales that we had in the quarter. This was just the inventories and the repricing of inventories from our linefill, our storage and our marketing team’s inventory.

Another way of looking at this is to answer the question of what would the run rate be for the balance of the year with identical operations and pricing that we saw in 1Q of 2020. The primary adjustment would be to add back the $24 million of inventory valuation write-downs to the $1.262 billion for the next three quarters, and this would provide us with an annual number above the midpoint of our guidance. To be fair, we had very low repair and maintenance costs this quarter, and we are not assuming that continues through the balance of the year.

But I think this analysis highlights how pleased we were, and are, with our execution here in the first quarter. So after touching on those issues, let’s dive into the key drivers. First of all, the primary drivers for the transmission in Gulf of Mexico segment was the decrease in recognized revenues, on our deepwater Gulf Star platform, which was coupled with the end of fixed payments on platform space. And we’ve reminded you of that several times, that actually, that fixed payments ended May of last year. And so this is you’ll hear a little bit about noise on this in the second quarter, and then we’ll have a normal comp, so that’s that.

Beyond this change on Gulf Star, the transmission in Gulf of Mexico was up $60 million from the first quarter of 2019. This was driven by Transco revenue growth from the Rivervale South to Market and Gateway expansion projects and the Northwest pipeline North Seattle project. Additionally, our first quarter of 2020 results include increased EBITDA from the Transco rate case settlement and the benefit of cost savings initiatives implemented in late 2019 by our operating teams there. Lastly, total deepwater gas volumes were up 8% year-over-year, mostly from the Norphlet pipeline and that gulf east projects that came online in the second half of 2019.

And next, in the Northeast G&P adjusted EBITDA, we saw we were up $58 million, and this was driven by higher gathering, processing and liquids handling revenue. A lot of new assets put in service in the second half of 2019 that drove this, and we are providing additional services to volumes that we are already gathering there. This, along with a relentless focus on cost containment and efficiency drove adjusted EBITDA growth of 23% for the Northeast operating area. Total gathered volumes consolidated and nonconsolidated grew by 4%, with the primary contributors coming from the Marcellus South, the Ohio Valley Midstream. I’ll remind you the Ohio Valley Midstream is the Northeast JV that we have with the Canadian Pension Plan Investment Board and then the Susquehanna Supply Hub also contributed to that growth.

This EBITDA and gathering volume performance resulted in this segment realizing $0.52 per of EBITDA per gathered Mcf. So I’ll remind you, that’s a measure that we talked about back at our 2017 Analyst Day when we laid out the our long-term aspirations for the area. And so just to remind you, that range that we talked about then was $0.50 to $0.55. So we wind up now in the middle of that range. So we’re really, really thrilled to have achieved that important measure. And I think that move from, as I recall, I think that was around $0.36 or $0.37 back then. So a really impressive move by the team as we’ve been able to continue to increase our unit lower our unit cost and continue to drive efficiency in that basin.

Of course, there’s a number of factors that have driven that, and we are really excited, though, to have the scale that we do have now in that area. And this is going to allow us to continue using our low-cost to drive competitive advantages and further growth in that basin. Moving on to West. The real story here is a steady business. Volume remains relatively flat and setting aside the noncash Barnett issue and NGL inventory write down, the West adjusted EBITDA was down about $13 million. The decline is mostly attributable to lower commodity margins, driven by substantially lower NGL prices, realized on our sold equity barrels during the quarter. So now I’m going to move on to looking at the natural gas demand picture. We talked a little bit about this on our March 25 call. And I just wanted to update folks a lot of different stories out there in the markets around natural gas demand. And so I wanted to give you the direct viewpoint that we have, as Williams, on this.

Overall, we’re seeing natural gas demand has remained strong, both broadly across the market and on our systems. In fact, we’re seeing evidence that natural gas is not only holding up nicely but even exceeding recent historical norms. And while it’s hard to predict very far into the future right now, we have seen demand for natural gas in the U.S., including the exports to Mexico and via LNG exports remaining strong. It’s a vastly different picture than what we are seeing in crude oil demand. Demand in the continental U.S. has generally been above the three year historical average in comparable weeks for natural gas. We have strong demand in the power sector. Industrial is down slightly. Res, com has held in very well despite mild weather. And LNG and Mexico exports have driven demand up over the prior year averages.

One thing I do want to make sure you can see in this chart on the left is that the week-over-week behavior of demand is a seasonal impact. The sequential declines have been, we have seen in weekly demand since January, are the normal behavior we see when we move out of cold winter month and into the shoulder months of more temperate weather before the heat of summer starts to drive electrical load due to air conditioning demand. So we only mentioned that. We know a lot of that is very obvious to most people, but we’ve certainly seen a lot of headlines coming out, talking about lower natural gas demand. And if you read through the headlines that go with that, you’ll notice that a lot of that is just normal demand associated with weather.

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Looking at the right-hand side, which reflects flow data right off our gas transmission systems, we continue to see normal behavior with deliveries generally staying within the normal range when compared to last year. And while the EBITDA generated by our regulated gas transmission systems is not impacted by volume fluctuations, thanks to the fully contracted capacity payments we received. We do monitor these volumes to get a sense for demand in the markets we serve and the gathering volumes that serve those markets as well. As we have consistently said over the last several years, our business is driven primarily by natural gas demand.

Current and near-term future demand drives revenue on our gathering and processing systems as the various sources of U.S. production meet this demand and long-term demand growth drives the opportunity to expand our gas transmission system. As more and more people see the benefits of consuming low-cost, abundant, clean natural gas, end users will continue to invest in gas consumption and the transportation capacity they need to access this reliable energy source. We will keep monitoring demand as we plan for the rest of this year and 2021 and beyond. One thing we are seeing right now is extremely low international prices for LNG.

European gas storage is very high right now after an even milder winter than what we experienced here in the U.S. And while this may affect demand for U.S. gas over the summer, we see this pricing issue as cyclical and not secular. As we look further out, we remain extremely confident in U.S. natural gas production as a low-cost supply to a world hungry for reliable, abundant, clean energy, and in our business strategy, to provide long-term value-based on that demand for natural gas. So now let’s turn to some of the key areas we believe investors are focused on now, and how our business looks through the lens of some of these risks and opportunities we know our investors are trying to assess. I’ll start with the market environment we find ourselves in now.

I won’t dive into all of the current and extending drivers of the oil price collapse but will lay out the distinctions between the drivers of low natural gas price and the drivers of low oil price. Low natural gas prices have existed here for a few years now, driven by supplies growing even faster than the growing demand we have enjoyed. The latest oil price collapse we have seen has been primarily driven by tremendous demand destruction. When you are in the business of moving these commodities, this distinction is everything. Confidence in abundant, clean and low-cost natural gas supplies have driven consistent demand growth of 24% over the last three years, and that growth in demand will continue.

On the other hand, lower demand from refined products ultimately means lower oil prices and lower volumes. So what does that mean for domestic supplies? With the oil price collapse, we expect associated gas from oil-producing basins like the Permian, Bakken, the SCOOP/STACK and Eagle Ford to decline, and we expect gas directed basins to gain market share. As producers begin shutting in some flowing oil production to avoid filling storage and selling their production at unacceptable prices, we’ll see reductions in associated gas accelerate. This decline will continue as the void in drilling and completions of oil wells begins to show the underlying decline in the large number of new wells supplying the market.

At the same time, as I mentioned earlier, we see natural gas demand has remained strong, and over the long term, we expect that strength to continue. So what is this all being this rapidly changing market environment, what does this all mean for Williams? We do expect the gas gathering we do in the oil basins to be impacted by the oil price shock both near-term shut-ins and longer term, the impact of lower prices for longer that will likely reduce capital available for U.S. shale oil production. The largest impact will be reduced will be the reduced growth in the Permian and DJ Basins business, including the associated NGL volumes from the DJ. In 2019, the Permian, DJ and Midcontinent basins were approximately 2% of our EBITDA, just to keep those declines in perspective. The Eagle Ford is our single largest onshore shale oil-facing business at 5% of our 2019 EBITDA.

We recently renegotiated the contracts with Chesapeake, our largest customer in the Eagle Ford from a cost of service contract, with rates that vary by year as volumes vary to a fixed fee contract, which has a minimum volume commitment. This contract, which was negotiated and executed in late 2019 became effective on January 1, 2020, and it is designed to insulate us from volume fluctuations in the Eagle Ford. It also includes language, which makes it abundantly clear that our contractual rights are linked directly to the minerals in the ground. Our Gulf of Mexico business is driven primarily by oil economics and is not immune to oil price risk. However, it is uniquely positioned versus onshore oil business.

The deepwater business requires a very long-term view given the multiyear, multibillion-dollar investments required by producers to bring on very large-scale reserves. The customer base is primarily international integrated oil companies or large-scale independents with significant expertise in the deepwater for whom existing assets provide synergies for future investments. With regards to future project opportunities, our, producer, customers in the offshore business will clearly be looking at oil prices, but it will be with a long-term vision for where prices will be in the next three to four years.

Williams will be impacted in the near term by some Gulf of Mexico production shut-in from small producers, but we do not expect that to be a significant volume. Also, remember that producers bear significant fixed cost when operating deepwater production, most of which don’t go away during a shut-in. So therefore, we expect offshore shut-ins if they do occur to be some of the shortest duration oil production shut-ins that we’ll see here in the U.S. Along with the dramatically lower oil and NGL prices has come well-deserved concern about our counterparty exposure with our customers, so let’s focus for a moment on our customer base and the practical risk of not getting paid for the terms of our contracts.

From our perspective, it’s very important to look beyond a simple credit rating breakdown and really look at the services being provided and the essential nature of the assets that we utilize to serve our customers. We think about our counterparty exposure much differently in the G&P business than we do in the gas transmission business. Counterparty credit quality is extremely important in any long-haul business, where there are a number of different ways to get gas to a wide variety of markets. In gas transmission, you rely heavily on the ability of your counterparty to pay you for the capacity over a very long term that the assets were designed and built for. We watch our gas transmission counterparty exposure carefully and have built a portfolio of contracts dominated by demand for investment-grade rated counterparties, customers who need to have capacity available to meet their peak demand rather than customers who are trying to find a market for their gas.

The gathering and processing business, due to the universe of E&P companies, include smaller, less capitalized counterparties. These are very accomplished operators. These are the independent producers who have led the charge in creating energy independence here in the U.S., but often with lower credit ratings or no credit ratings at all. We do value high credit quality amongst all our counterparties and closely monitor the credit quality of our portfolio of G&P customers, but we also mitigate the credit risk we necessarily take on in the GMP business with scale and with wellhead or well pad connectivity.

A large-scale system that connects directly into producers’ reserves is difficult to reproduce, and our customers will honor our contracts and utilize our services even when they’re in financial distress. We have a strong track record of seeing the contracts for our wellhead gathering services survive a wide range of corporate actions or restructuring processes, even bankruptcy and by our producing customers. In fact, we see the real risk of gathering gas for financially distressed counterparties as a risk to growth rather than a risk to the revenue we earn on the flowing reserve. A distressed customer will not be able to fund the sort of drilling capital necessary to grow their production and our gathering revenues.

So we hear a lot of concerns out there about bankruptcy, but I would just tell you that the real issue for us is we’ve got a lot of great acreage dedicated to us, and what we want are adequately capitalized customers being able to drill on the great debt acreage that’s dedicated to us. And that’s the real impact that we see during this financial stress. The picture we have been painting through this discussion so far and through our financial performance is one of stability and predictability. That stability and predictability is a bedrock on which we build a conservative financial policy and capital allocation process that drives the return of value to our shareholders.

We pay a very attractive dividend based on our $0.40 quarterly dividend, which annualizes to $1.60 and yesterday afternoon’s close of $19.13. That $1.60 dividend offers an 8.4% yield. This very attractive yield is well-covered, and WMB is one of the very few large infrastructure players that is also more than covering its growth capital spending as well. We have been reining in our growth capital very tightly over the last couple of years as we have been working hard to improve our balance sheet. Many of our peers have talked about significant cuts to capex budgets as they are now scrambling to cut this year. And we’ve already traveled much of this road, making significant cuts to our capital spending year-over-year for the past several years.

In fact, our total capital expenditures, growth in maintenance in 2019 was $2.4 billion, which was 40% below the 2018 total capital expenditures of $4.2 billion, and with our latest thoughts on growth and maintenance capex here for 2020, we are now positioned to see another 40% reduction in total capital here for 2020. Our stable cash flow and disciplined capital spending have driven down our leverage, maintaining a strong, flexible balance sheet and investment-grade credit metrics is very important to us, both financially and operationally. We believe an investment-grade credit rating keeps our cost of debt down, but also reduces the risk of the company in the eyes of the equity investors, both current and prospective equity investors.

And while we focus mostly on the long-term positioning of the company on this slide, I do want to reiterate our 2020 guidance ranges remain unchanged, but we do expect to come in at the lower end of the range for adjusted EBITDA and both on growth and maintenance capex as well. Regarding adjusted EBITDA coming in towards the lower end of our guidance range, we see that being at the lower end of the range is being driven by lower-than-expected volume from the oil basins that we talked about earlier, primarily the DJ Basin and a much lower NGL margins we are currently experiencing. We have not assumed prolonged shut-ins in our oil basins nor have we assumed increased dry gas drilling.

We also, on the other hand, we don’t assume that we will continue to enjoy the same degree of low maintenance and repair expenses that we enjoyed in the first quarter of this year. And so as we think about the here for 2020, a number of variables laying out there, as we’ve talked about, one, prolonged shut ins, I would tell you, so far, we see those as fairly minimal. But we do want to make sure you understand, we are not expecting wide-scale or prolonged shut-ins in our guidance right now. We also, as we mentioned, don’t have the uplift that we might see in the last half of the year as well.

Moving on to capex expectations. We’ve been able to reduce capex due to lower than budget performance on our projects and execution as well as lower producer activity, which has reduced the need for capex in a lot of our gathering operations. As a result, we now could see total capital spending come in below the low end of our guidance range. However, as previously mentioned, we only had a very small amount of capital in our forecast for our NESE project, since we were not going to allocate capital to the project until we receive necessary permits. We remain confident that NESE will ultimately be approved. And if this happens as soon as June, the other reductions mentioned will allow us to still be at the low end of our capex guidance range.

So just to clarify that, we do expect we would be still at the low end of the range for capex if we are fortunate enough to get NESE moving here as soon as June. On the other hand, if we don’t, we actually would come in below the current capex guidance range that we have out there. In closing, we believe our business is very well positioned to benefit from continued demand growth in natural gas over the long term, and that our strong competitive position and conservative financial model makes us a resilient business that can deal with near-term challenges in the market while positioning us very well for the long term and the strong growth that’s ahead.

So with that, let’s go ahead and transition to our Q&A session, and thank you again for joining us today.

Questions and Answers:

Operator

[Operator Instructions] Your first question comes from the line of Jeremy Tonet with JPMorgan. Your line is open.

Jeremy Tonet — JPMorgan — Analyst

Hi, good morning. Just wanted to kind of build on some of those points there, I guess, with your producer conversations. I mean it seems like natural gas prices, further on the curve, continues to climb here. And so I’m just wondering if you could share a bit more on what type of operating leverage you think Williams would enjoy as gas prices improve and producer activity ticks up in response to what we’ve seen here?

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Alan S. Armstrong — President And Chief Executive Officer

Yes, Jeremy, thank you. We have a wide variety of rates out there in the market. And so it kind of obviously depends on where that volume is produced. And so I think that’s very dependent. The good news is, I think as we’re demonstrating in the Northeast, we’ve got a very strong leverage where our cost that we’ve been able to really keep down even as volumes have grown. And so if we see a lot of that growth occur in the Northeast, it’s going to continue to be limited capital and limited incremental operating costs. So pretty good operating leverage to that. In the Haynesville, that’s probably the other area that we would expect to respond here in the near term.

And the operating leverage there is pretty similar. We’ve got pretty low incremental operating cost, so a lot of revenue will drop to the bottom line there. So as we’ve said in the past, the rates out there on the dry gas gathering are in the $0.30 to $0.50 range. And so that’s kind of what you can take quite a bit of that to the bottom line in terms of volumes that we have. If we happen to see some of that come through on rich gas or processable gas, which we are seeing right now occur in the West Virginia, we’re seeing volumes come up pretty nicely there, we obviously get a much higher margin on that just because we’re offering additional services to that. So I would say the lower operating leverage that we have is in the dry gas and a little bit higher operating leverage against the rich gas or the process.

Jeremy Tonet — JPMorgan — Analyst

That’s helpful color. And just wanted to kind of pivot, if I could, to Regional Energy Access. It seems like other pipes in the northeast are continuing to face challenges, getting built here. And just wondering what you could share with regards to how that project is developing and what opportunities you see there.

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Jeremy, this is Micheal. Regional Energy Access continues to move toward a FERC filing early summer. We’re still seeing a bit of a slowdown in the commercial execution of our final proceeding agreement that it directly attributable to COVID-19 and our inability to meet directly with the customers. But we are still executing those, and we have gained momentum on that project, and continue to. And just as a reminder, the majority of those facilities are in Pennsylvania.

And we think that’s why we have a significant benefit and opportunity to get our project permit approvals in a timely fashion. And just as a reminder there, we only have one facility that we project to be outside of Pennsylvania and that’s a electric-driven compressor station in New Jersey, which we feel like don’t have any permitting issues at all. So commercial activity is still underway, but we are in the midst of preparing the prefiling documents and expect to have those in FERC in this summer.

Jeremy Tonet — JPMorgan — Analyst

Got it. That’s helpful. Thank you.

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Thanks, Jeremy

Operator

Your next question comes from the line of Colton Bean with Tudor, Pickering, Holt. Your line is open.

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Morning, Alan, I think you just noted that you’re seeing some decent trends there across the rich gas exposure in West Virginia. Thinking about the system more broadly, can you update us on what you’re seeing across some of your more NGL-exposed areas and condensate particularly?

Alan S. Armstrong — President And Chief Executive Officer

Yes. Mike, do you want to take that?

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Yes. Colton, we are seeing some concerns early on in regard to condensate production, where the producers were chasing condensate earlier this year. I think if you go back and look at the Southwestern call incurred a few days ago, they feel like they’re not going to have any shut-ins due to any condensate issues for the month of May. And that’s obviously good for us. We’re a large customer there, they’re a large customer of ours there in West Virginia. So we’re pleased to see that announcement from them.

There are definitely challenges in some of the areas. The Eagle Ford certainly had some condensate challenges there, and we are working with our customers there to find opportunities. We’ve had a team working on the condensate opportunities to store condensate for customers, and we have opportunities to be able to do that for them if they so choose to do that at our facilities around the country.

And so we’ve given a lot of options after our customers that they want to continue to produce and move those condensate volumes into our potential storage opportunities for them. On the NGL side, we aren’t seeing as much pressure on the producers from a production standpoint as you would on the condensate side. So I think we are seeing some increase. I think prices are actually moving higher, and NGL prices are continuing to move stronger from where they were over the last several weeks. And so we’re not seeing as much pressure there as we are on the condensate side.

Colton Bean — Tudor, Pickering, Holt — Analyst

Got it. Appreciate that. And then just on the National Grid side. So I think you all commented that you think you could see approval there for Northeast supply as early as June. So I guess, in terms of key hurdles to watch, what exactly is it that you guys are evaluating? And then if we weren’t to see approval by June, is the in-service potential step change into 2022 or what sort of impacts would you expect there?

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Yes. I’ll take that one as well. So the National Grid concluded their public comment meetings that went virtual on the majority of those and had a 2-week extension in the deadline. So those concluded on May 1. And I think the resounding thing that became very clear there is that the NESE project is the only opportunity for them to meet their long-term solutions. If you recall the settlement agreement that they had with the state, required them to provide a long-term solution to the state by June, and that long-term solution had to be in service by fall of 2021. And it’s abundantly clear that NESE is the only opportunity to be able to do that.

The one thing I do want to mention, we watch the demand very closely across the U.S. and we certainly watched it very closely in the New York metropolitan area for natural gas. And we’ve seen virtually no impact due to the COVID-19 situation. And if you weather-normalize the demand up there, it looks like a normal year. It’s been a very warm year in January, February and March in the Northeast. April was about normal. And so when you weather-normalize those demand pictured across those four months, it looks just like a normal year for gas demand.

So we see no impact there. It certainly wouldn’t factor into any decisions that our customers would be making there. And you can make the argument that maybe commercial construction possibly could slow down. But we do think from a long-term standpoint, natural gas demand is going to be increasing in the New York metropolitan area just because of the amount of conversions of fuel oil still need to occur there as well as the growth in infrastructure that’s being built in New York City.

We’ll also say that through this public comment process, where we’re prosecuting our permits, we’ve seen over 16,000 positive public comments come in to both New York and New Jersey to support our project. There’s more than 80 elected officials and community organizations that also support the NESE project, and it made these public comments on the record. The upcoming deadline on the 401 certifications that we have are May 16 in New York and June five in New Jersey. And so that’s really the key markers that you should be watching out for here.

And to answer the last part of your question, if we do not get those approvals in May and June from both New York and New Jersey, we’ll have to go back and reevaluate with our customer, what the expectation is there. But we certainly could refile those permits as we’ve had in the past, and have those turned around fairly quickly if New York and New Jersey choose to do so.

Colton Bean — Tudor, Pickering, Holt — Analyst

And I appreciate that.

Operator

Your next question comes from the line of Gabe Moreen with Mizuho. Your line is open.

Gabe Moreen — Mizuho — Analyst

Good morning, everyone. Alan, if I could just ask, it seems like also producers are taking a different approach to their outlook for nat gas prices next year and how much they’ve been willing to hedge the 2021 strip yet. Can you tackle maybe the insight you’ve got in terms of some of the private producers, whether it’s in Sino, in the Utica or some of the producers around your Haynesville acreage and how they’re treating 2021 and whether they’re and what their outlook might be for adding rigs and how soon that might happen?

Alan S. Armstrong — President And Chief Executive Officer

Yes. I would say there’s a lot of people kind of still licking their wounds a little bit from the low price environment that we’ve seen here in the first quarter, and that’s not forgotten easily. And I think they want to make sure that they’re going to be very disciplined around the capital and allowing themselves to make decent returns. And so and I’m not speaking to any one producer here, just to be clear, but I do think that the very low prices that they’ve had to endure on both the GAAP and the NGL prices in some of these locations has got them really thinking hard about how to move forward. And frankly, I think they see the fundamentals perhaps being even stronger with that kind of cost discipline to the degree that takes hold across the space, which seems to be, frankly, that the fundamentals will drive even higher prices.

And so if you look this morning, I think the January 21 prices were up to 3 20 for January 21. So they may be exactly right on that and thinking that the fundamentals will continue to drive those prices up. So I think they’re really going to make sure that they’re not just doing this to turn bids, but to make really good value for their shareholders and their owners, and wait and are going to be patient to make sure that the price really allows going to make some decent returns. And frankly, that’s the kind of discipline, I think, that will make the space healthy over time.

Gabe Moreen — Mizuho — Analyst

Understood. And then maybe, John, if I could get sort of updated thoughts from you and where you’re thinking about debt markets now? Clearly, things of improved quite a bit since a couple of weeks ago in the update call. And I guess, just your thoughts around taking some of off the revolver when you put those early maturities on the revolver.

John D. Chandler — Senior Vice President, Chief Financial Officer

Yes. No, those rates have significantly improved. Little painful from where they were in February at an incredibly low rate. But as we look today, the rates are very attractive for Williams and for Transco. And so it’s we’ll watch the markets, and if we feel like there’s a good opportunity, we’ll certainly take advantage of that and try to get some off of our revolver. We have we still have $1.7 billion on a revolver. But I’d say we also have $700 million in cash. So we’ve got a very strong liquidity position. Our revolver, again, is $4.5 billion and doesn’t mature until 2023. So we can be patient. But just to be clear, rates are attractive, and our bond spreads have really traded in, in the last couple of weeks.

Gabe Moreen — Mizuho — Analyst

Great, thanks.

Operator

Your next question comes from the line of Alex Kania with Wolfe Research. Your line is open.

Alex Kania — Wolfe Research — Analyst

Thanks, good morning. Just a question, I guess, just on Gulf of Mexico. First, I guess, just thinking about making sure that we understand how the sensitivity is on volumes work. It sounds like, again, you feel like from large producers, there’s not going to be a big move. But again, just wondering if volumes do move, does that directly impact your bottom line? Or is there some protection within Targa contracts work on a cost base basis? And then related to that, maybe if there’s any impact on capital related to, I guess, the Whale delay that you announced a couple of days ago?

And second question is just thoughts on the NWP 12 Permit. Do you use that typically for your construction activities? Is that going to cause any complications for any planning that you’ve cut on the gathering or transmission over the next few months until we get some resolution on that?

Alan S. Armstrong — President And Chief Executive Officer

Yes, I’ll take the first question there broadly on the deepwater, and then have Micheal answer the Whale and the NWP 12 question. On the deepwater, for the most part, there are some MVCs and some fixed payments out there. But for the most part, because a lot of MVCs are so much below the actual volumes that people are sitting at today, you should consider our deepwater business to be pretty well driven by volume, so both on the oil and the gas side. So I would it’s not that complicated out there for the most part.

It’s I mean there are places like the Northwood and places like that, that were true-up on an annual basis, but you wouldn’t see that in a quarterly basis. So anyway, so newer assets like Norphlet tend to have those, and the older assets, those MVCs have we’ve gotten our capital back in those MVCs where those fixed payments have gone away. Just like Gulfstar, as we mentioned, the fixed payments on that, terminated the majority of the fixed payments terminated in May of last. Mike, if you’ll take the Whale and the NWP?

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Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Sure, Alan, thanks. On Whale, we actually before all of the oil bright shock occurred, we actually placed some orders for some equipment. And we’ve got more favorable timing terms on those orders. And so our capital would actually be reduced this year. It’s just a timing issue for the most part, though, prior to the announcements came from the Whale customers. Since the Whale customers have made their announcements, we’ve had conversations with them. They’ve not asked us to change course in any fashion in regard to our current undertaking of engineering and procurement of materials to support their project, although they have announced an FID delay.

So right now, it’s a steady issue good in regard to our performance under our reimbursement agreement with those Whale customers. And on the nationwide 12 question, as you all probably are well aware, the connected oil pipeline in Montana, they suspended authorization of the nationwide to permit for that project, and it certainly is something that we’re all looking at across the industry. The core engineers has stated they’re not authorizing any new projects right now under the nationwide 12, but they’ve not shut down any projects that we know of, and certainly none of ours, that were being performed under the nationwide 12.

We don’t think this is going to be a significant issue to Williams. And for example, in Pennsylvania and New Jersey, they don’t even use the nationwide 12 permits there. So it’s certainly not an impact at all there and anywhere that we were going to use those this year on new authorizations. It was just small pad connections in our gathering systems for the most part. And we can pivot to a different permitting team for those and achieve our permitting goals for those projects. And so as of now, we’ve got no project shutdown and every core engineer’s office that has jurisdiction over our permit in each one of those jurisdictions, we’ve had conversations with them, and they said they have no intention of shutting down any projects that are currently underway with the nationwide 12 permit.

Alex Kania — Wolfe Research — Analyst

Great, thanks very much.

Operator

Your next question comes from the line of Tristan Richardson with SunTrust. Your line is open.

Tristan Richardson — SunTrust — Analyst

Hey, good morning. Really appreciate all the commentary this morning. Just a follow-up question on the Northeast G&P. I mean with the volumes we’ve seen in 1Q and your commentary, perhaps suggesting even the rich gas volumes remain resilient. We think about the $1.4 billion in EBITDA number you’ve talked about in the past, should we think of that as still a relevant number in the current environment in Northeast G&P?

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

I this is Micheal. I’ll take that. I think we had tempered our expectations on growth there coming into this year, last year. That’s why you saw significant reduction in our capital. But if you do a run rate on the Northeast, I think we were at $370 million EBITDA this quarter, and we would expect to see some continued flat performance, if you will, through the majority of the Northeast PA production areas. As everyone knows, Cabot’s talk about going into maintenance mode with flat production for the year.

We’re seeing some growth in the Bradford still, under our cost of service agreements up there. And we do think some of the areas in West Virginia will be a more of a bright spot in the coming several quarters, probably towards the end of the year into next year. And so I think we do have some line of sight, ultimately, to be able to get to that $1.4 billion, it might be a little bit delayed from where we were hoping, but we had those expectations tempered coming into this year.

Tristan Richardson — SunTrust — Analyst

Helpful. And just a brief follow-up. With respect to Bluestem, with the frac chain online now, can you see contributions from any of that capacity today? Or any fractionation contributions would come when Bluestem comes online early next year?

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Yes. Assuming that frac seven under target controlled is taking product, we will get revenue from that. So and it is that we understand. And so we will get revenue from that prior to Bluestem coming online.

Tristan Richardson — SunTrust — Analyst

Thank you guys very much.

Operator

Your next question comes from the line of Shneur Gershuni with UBS. Your line is open.

Shneur Gershuni — UBS — Analyst

Good morning, everyone. Thank you for the extended update today. And a lot of my questions have been asked and answered. But maybe to follow up on Gabe’s question a little bit here, but in a different way. When we think about the producers in the Northeast, a lot of them are not really well-capitalized coming into this, excluding Cabot, which I realize is a very important customer of yours. Are we sure that the higher gas prices ensures that we get higher volumes or higher volumetric opportunity for Williams? Or is there a chance that they sit there and just sort of take their production ideas and enjoy the high prices and not accelerate capex? Just kind of trying to think about how we should think about it from a volumetric perspective in 2021, just sort of given the starting place from where the producers were.

Alan S. Armstrong — President And Chief Executive Officer

Shneur, are you speaking just to…

Shneur Gershuni — UBS — Analyst

So taking them all?

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

The Northeast.

Alan S. Armstrong — President And Chief Executive Officer

Yes. Well, I would say, as you would think, a variety of producers and financial drivers out there, some are well hedged and are taking advantage of the cost low available cost structures to them out there right now and growing very successfully and not really missing a beat. On the other hand, you have players for us like Chevron up there that has announced the sales process and have been kind of pulled back on their drilling operations. So that’s probably the extremes of that. But as I mentioned earlier, I do think that some producers are going to sit back and wait to see how firm these prices will get.

They keep moving in the right direction. And I think they’re waiting to I think they believe that the fundamentals are on their side. And so if you translate all of the negative discussion around oil and shut-ins and demand disruption, if you believe that strongly, then you have to turn around and believe that gas is going to have a big call on it in these gas-corrected basins. And so I think that’s what you’re seeing is some of them having quite a bit of confidence in the fundamentals and are waiting to make sure that those fundamentals show up in the way of price or they commit to anything. But be clear, these are all there’s not I can’t point to a large producer that we deal with out there that I don’t have quite a bit of respect for. The way they think about this, they just have different motivations and drivers out there in front of them. But they all, I would say, are always in the case of planning.

So they’re not sitting back right now, even though it may appear that way. They’re not sitting back on their haunches and not planning for what looks like opportunity for growth in the future. But I think they’re only going to pull those triggers when they’re confident that these prices are something that they can lean into. So I would say what we are seeing pretty visibly, there’s a lot of planning for growth, but not necessarily a commitment to that growth just yet. And but I think there’s a lot of belief in the fundamentals that exist out there. And again, it’s kind of hard to believe in all the carnage on the oil side and not believe that on the pull on the gas side.

Shneur Gershuni — UBS — Analyst

Maybe as a follow-up on that, maybe this is difficult to speculate about. But do you see some scenarios where maybe some of them, just given how difficult capital access is right now for them, that they potentially do JV and do like drillco JVs and so forth with private equity as do you kind of see that as potential avenue for some of them?

Alan S. Armstrong — President And Chief Executive Officer

I think more of that if you think not necessarily the Northeast producers, I think we’ll see more of that in the Haynesville area, where there’s a lot of easy acreage to go hit a lot of private companies that are even less capitalized in some cases. But they’ve got some very there’s not a whole lot of risk involved in the development there and certainly not a lot of risk in getting the gas to the markets. And so I think we’ll see a little more of that kind of activity like the…

John D. Chandler — Senior Vice President, Chief Financial Officer

One thing I do want to go back to a question that was asked earlier about Northeast EBITDA coming in. I believe the question was above $1.4 billion. And I would tell you, coming in earlier this year, we felt like perhaps we come in under that level just because Cabot was going back to maintenance mode, and we saw Chevron signaling they were going to slow some of their activity down. But again, remember, we had a really good first quarter, and our volumes are really good, really strong. And of course, things are starting to look better for the Northeast and the latter half of the year as well. So as we look at it today, we do believe we’ll be operating above $1.4 billion in the Northeast for the year.

Operator

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

Praneeth Satish — Wells Fargo — Analyst

Hi, good morning. Just in the Haynesville, can you maybe just give us a breakdown of the customer mix there? How much is Chesapeake versus privates? And then in terms of potential growth in the Haynesville, if it does occur, would you expect that to come more from the public or private producers in the region?

Alan S. Armstrong — President And Chief Executive Officer

I’m going to have Chad Zamarin, who has been dealing with a lot of the opportunities out there to address that.

Chad J. Zamarin — Senior Vice President, Corporate Strategic Development

Yes, sure. Thanks. In the Haynesville, Chesapeake is still about 70% of our volume. But if you look back about three years, it would have been a much higher percentage even at that. So we’ve seen pretty rapid growth in third-party volumes from primarily private producers. Alpine is one of those producers, nailing Guzman. Comstock is a producer that’s not private, but we’ve been picking up additional activity from. And to the question kind of earlier, we have seen those producers in the Haynesville take advantage of the current pricing environment and extend their hedging.

And to Alan’s point around access to capital for drilling in the Haynesville, the ability to hedge out, now, many of these producers are hedging more than 24 months out on those Haynesville wells are very much front-end weighted from a value recovery perspective. And so those Haynesville producers have a pretty good opportunity to lock in their production plans over the next couple of years. And so the recovery of kind of the back end of the price curve has really created a very stabilizing effect for ongoing development. In Haynesville, we actually think we’ll see additional growth as a result.

Praneeth Satish — Wells Fargo — Analyst

Great. And then can you maybe just rank order which of the which of your oil-directed regions would get hit the hardest from potential shut-ins? And then how many quarters would you expect the shut-ins to persist for? Is this a one quarter, two quarter or for the balance of 2020?

Micheal G. Dunn — Executive Vice President And Chief Operating Officer

Yes. This is Micheal. I’ll take that. From a shut-in risk, I would say the Eagle Ford is probably the highest, at least in our acreage area because of the condensate that the customers are producing there. But we are protected by an MVC, for example, on the Chesapeake contract. So even if the volumes do decline, we do have an MVC protection underlying that, which we think would be very strong for us from a protection of our revenue there in regard to that.

So I’d say the Eagle Ford is probably the highest. The DJ is probably one as well, where they’re also seeing some of the same type gravity production there from the condensate and oil that they’re chasing in the DJ. So we would also have some similar shut-in risks there. Gulf of Mexico, you’ve got some of the smaller independents in the Gulf of Mexico. That’s probably next on the list. But so far, we’ve not seen any of the large producers in the Gulf shut in any production.

Praneeth Satish — Wells Fargo — Analyst

Okay, great. Thank you.

Operator

Ladies and gentlemen, at this time, I will now turn it back over to Mr. Armstrong for closing remarks.

Alan S. Armstrong — President And Chief Executive Officer

Okay. Well, thank you all very much for joining us this morning. A great quarter. We’re really excited to see the execution that we had in the quarter. And we think the fundamentals are very strong for our business and the way we’re positioned out in front of us. So thanks again for joining us this morning.

Operator

[Operator Closing Remarks]

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