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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, everyone, and welcome to the Williams Second Quarter 2020 Earnings Conference Call. Today’s conference is being recorded.
At this time for opening remarks and introductions, I would like to turn the call over to Mr. Brett Krieg, Head of Investor Relations. Please go ahead.
Thanks, Lindsey. Good morning, everyone. Thank you for joining us and for your interest in The Williams Companies.
Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Chandler, will speak to this morning. Also, joining us on the call today are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Senior Vice President of Corporate Strategic Development.
In our presentation materials, you will 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.
Great. Thanks, Brett, and thank you for all for joining us today. We’re proud to share the results of the strong second quarter that really is a testament to the stability and predictability of our business.
As John will share in more detail, Williams exceeded its internal plans and also expectations by the Street and showed just how durable this business can be against a number of headwinds, including shut-ins in the Deepwater Gulf of Mexico for a variety of reasons, including a COVID breakout on one of the platform – larger platforms that serves us, Tropical Storm Cristobal and a variety of price-related shut-ins that expanded beyond the Gulf of Mexico to places like the Eagle Ford and the condensate production in the Marcellus.
So lots of headwinds for the quarter. But really, the variety that we have and the durability of our business really shown through. It’s not been an easy environment for most companies to navigate, and a lot of people are likely asking you to look past this quarter and focus on the remainder of the year. But for Williams, it is quite the contrary.
We want to focus on this quarter’s performance, because Q2 was a real opportunity for us to demonstrate the stability of our business and the long-term benefit of a strategy that has been built on the sound fundamentals of low-cost, clean natural gas.
So let me turn it over to John to walk through our results, and then I’ll share some thoughts on the overall natural gas market and compare Williams volumes up against the broader market stats, and then I’ll hit on some of the key investor topics before we get to Q&A. So, John?
Thanks, Alan. We’ll talk to Slide 1 here for a moment. We are obviously very pleased, and frankly, we’re not surprised with the results this quarter. As Alan mentioned, while the energy industry faced a very difficult environment over the last quarter, our volumes and earnings really shine through, and you can see this in our statistics for the quarter.
Cash flow from operations improved by 7% year-over-year. And while adjusted earnings per share and adjusted EBITDA looks flat to last year, realize that there are a few unusual items that cloud the comparability, and namely, those relate to the reductions in deferred revenues and the impact of some temporary shut-ins in the Gulf of Mexico. And those two negative items were offset somewhat by the benefit of NGL prices on our inventory in the West.
If you exclude these items, our adjusted EBITDA actually was up over 3%. We will discuss EBITDA variances more in a moment. Distributable cash flow was down for the quarter. But importantly, in the second quarter of 2019, it benefited from an $85 million alternative minimum tax refund. We expect a similar refund this year, but that will come later this year.
Factoring this out, distributable cash flow also increased $15 million, or about 2%, reflective of the EBITDA increase we saw this quarter. The strong distributable cash flow generated very solid dividend average of 1.64 times, showing that our dividend is very safe. If you expand that for the full-year, distributable cash flow and coverage are on track to achieve the midpoint of our original guidance range, even with our guidance of EBITDA being in the lower-half of our guidance range.
This is because of the lower-than-expected level of maintenance capital spending this year versus our original plan, and due to the benefit of tax refund we expect to receive in the second-half of this year.
Intentional capital discipline and the shifting of some project spending continues to drive capital spending down, and as a result, our free cash flow up. And to that point, expansion capital spending for the quarter and year-to-date is about one half of what it was last year.
With expansion capital spending now expected to come in the $1 billion to $1.2 billion range and looking at our EBITDA and distributable cash flow forecast, we still predict that we’ll produce excess free cash flow this year above all dividends and capital expenditures.
The strong cash generation and capital discipline has helped deliver on our goals to improve our leverage metrics. Our net debt divided by our last 12 months EBITDA produces a ratio of 4.31 times and reflects a nice improvement over the metric from the same time last year.
And finally, while not on this page, we did end this quarter with $1.1 billion in cash, of which $600 million will be used to retire debt that matures in November. This cash, along with our untapped $4.5 billion revolver, provides significant liquidity to the company.
Now, let’s go to Page 2, which is our adjusted EBITDA waterfalls. And let’s dig in a little bit deeper about the variances of our EBITDA results for the quarter. Again, Williams performed very well despite a pretty tough energy market.
As I mentioned a moment ago, we believe it’s important to isolate a few unusual things to make the numbers more comparable and reflective of the ongoing performance of the business. We’ve identified those unusual items, which are shown on this chart as comparability item and they totaled $42 million. And they consist of three things.
The first is a $32 million reduction in EBITDA tied to non-cash deferred revenue step down in the West around our Barnett Shale franchise area and in the Gulf of Mexico around our Gulf East franchise area. As a reminder, on deferred revenue, we received significant upfront cash payments several years ago, but did not recognize revenue at time. We have been amortizing those payments that we received into income over the last several years. And that amortization has been shrinking year-over-year.
The second unusual item is that related to our Deepwater Gulf of Mexico shut-ins that occurred during the quarter, and they had a negative $24 million impact to our results. These shut-ins were due to customer planned maintenance, which was significantly extended because of a COVID outbreak on a platform of one of our producers. It was also impacted due to Tropical Storm Cristobal. And then finally, it was impacted due to some price-related shut-ins that occurred during the second quarter.
The third unusual item that benefit – is the benefit of the rebound of the NGL prices that had a positive impact on our inventory value this quarter. You may recall in the first quarter, we highlighted reduced commodity profits due to what was a quick move down in NGL prices, causing a non-cash write-down of operational inventory and accounting losses on inventory sales in the first quarter.
That turned around this quarter, driving a $14 million improvement in marketing results, partially recapturing some of the loss we noted in the first quarter. It’s important to note that this is not us building inventory for speculative purposes, it’s just our operational inventory, primarily linefill. It’s also important to note that when you look at our West results, understand that the first quarter commodity results were understated because of this item and the second quarter results were overstated.
So this is not really a meaningful variance for commodities year-to-date in comparison to last year. We called out each of these three items, because, again, we feel it’s important to note their impact on the current period. And it allows – by separating those items, it allows for a better understanding of the ongoing performances of our business.
With that out of the way, our Transmission & Gulf of Mexico assets produced results that were $28 million better than the same period last year. A big portion of this increase came from new projects put into service on Transco, including Rivervale South and Gateway projects, that were brought into service late last year and the Hillabee Phase II project, which is brought into service this quarter.
In addition, this quarter benefited from Transco’s rate case settlement, which we did not reach settlement terms until the third quarter of last year. And finally, this quarter benefited from lower costs, both savings initiatives started last year and additional efforts we’re making this year.
While the Gulf of Mexico was not a contributor to the growth in EBITDA this quarter, volumes and revenues have already rebounded from the shut-in issues experienced during the quarter. And as of July 1, all affected production is back online.
Now moving to the Northeast segment, it continues to come on strong, contributing $44 million of additional EBITDA this quarter. Collectively, total Northeast gathering volumes grew 7% in the quarter and processing volumes were up 17%. These higher volumes drove revenue growth and, of course, we are realizing more revenues per gathered Mcf due to additional revenues earned from processing, transportation and fractionation of gas and NGLs.
Equity method investments also drove EBITDA growth, where we benefited from higher Bradford volumes due to a gathering expansion of that system in late 2019. Higher volumes from our Laurel Mountain Midstream joint venture, where volumes reached their highest peak in over three years in June; and our Marcellus South system, where we benefited from several new wells coming online during the quarter.
Finally, the Northeast also benefited from cost reduction efforts, much of which began last year, as well as some favorable maintenance expense savings. As a final note in the Northeast, our adjusted EBITDA per gathered Mcf for our Northeast operated assets, when you include a proportion of items for non-operated assets is now $0.52 per Mcf in the second quarter of 2020, compared to $0.48 per Mcf this same time last year, that’s an 8% increase.
Now moving to the West. That segment declined $32 million that was largely – that reduction was largely the result of special revenues realizable last year that were not repeated this year.
When looking at the ongoing health of the West segment, it’s really important to dig into the details of these unusual items. Those special revenue items in the second quarter of 2019 that I mentioned were the MVC payments in the Barnett Shale that ended in June of last year and the final cost of service contract true-up in the Mid-Continent, which benefited the second quarter of last year. And, of course, neither of those were repeated this year.
Beyond these items, gathering revenues were down, but were offset somewhat by lower cost. Combined gathering volumes for the West declined by 1% for the quarter. However, this was heavily influenced by some shut-in volumes in May in the Eagle Ford. If you exclude the Eagle Ford franchise area, volumes on all of our other systems collectively were up 2%.
Now, as it relates to Eagle Ford basin, our gathering agreement there is protected by a minimum volume commitment. And during the quarter, even though volumes were less than the Eagle Ford, we actually realized increased revenues from the minimum volume commitment.
Finally, lower costs also benefit this segment as we keep a relentless focus on efficiency and control. One other odd thing you may note in our statistics on the NGL and crude oil transportation line is a meaningful drop in volume, which comes from our Overland Pass Pipeline. This decline did not have an impact on our EBITDA, given that a shipper on the pipeline agreed to pay us a fee and keep us hold on revenues in lieu of shipping dedicated volumes on that line.
Now moving to Slide 3, our year-to-date results. You can see that year-to-date results showed growth of nearly 2% in adjusted EBITDA, driven by many of the same factors affecting the second quarter growth.
Barnett and Gulfstar non-cash deferred revenue step down accreted a $53 million reduction in EBITDA year-over-year, deepwater shut-ins that we just talked about in the second quarter accreted a negative $21 million reduction in EBITDA, and the net impact of commodity price fluctuations on the first and second quarter collectively accreted a negative $10 million headwind.
So if you take those comparability items out of the mix, year-to-date adjusted EBITDA actually results in a 5% increase. The West is off for many of the same reasons we described in the second quarter. The Northeast is a huge part of the growth year-to-date, adding $112 million in EBITDA this year over last year, with overall volumes up 6% and incremental revenues being realized from processing, transportation and fractionation of gas and NGLs.
And the Transmission & Gulf of Mexico assets are delivering growth as well with an uplift from expansion projects, the rate case settlement and expense reductions, and those positives are offset somewhat by some – by lower Gulf of Mexico profits. Again, all in all, despite a tough market, we’re off to a really good start for the year.
I’ll now turn the call back over to Alan to review some of the key supply and demand fundamentals. Alan?
Great. Well, thanks, John. And now, let’s look at the fundamentals that continue to support our business here on Slide 4. As we’ve consistently stated, our strategy depends on natural gas demand. And many people assume that natural gas demand would be greatly diminished by COVID-19 and a stalled economy. Fortunately, we have not seen that play out at all. In fact, natural gas demand has continued to grow, both broadly across the market and on our systems, in particular.
Overall, Lower-48 demand was up 2% from the second quarter of 2019. In fact, the only segment that did not grow was industrial load. And even industrial load was only down slightly about 0.6% and most of that was really early in the 2Q. So we’ve actually seen that rebound back up normal levels. But really at that level, you pretty well call that flat.
On the power gen side, loads remain strong with 2Q 2020 tracking 3% higher than the 2019 2Q levels. And the early numbers for the month of July here look like this healthy trend is continuing into the third quarter.
This is especially impressive if you consider that over the last 18 months, over 600 projects, representing an additional 20 gigawatts of renewable power generation capacity have been installed in the U.S. And the U.S. continues to show how powerful the combination of wind, solar and gas-fired generation can be when we’re up against meeting the dual challenge of providing low-cost and reliable energy, while at the same time lowering greenhouse gas emissions.
So there’s a lot of conflict, a lot of discussion, a lot of political bent that goes into this issue. But at the end of the day, the U.S. is really doing a nice job of combining the benefits of renewable power with gas-fired generation. And we continue to see that show up in the numbers on a fact basis, despite a lot of the media and political bantering that goes around this issue. We really are seeing positive improvement here in the U.S. on both emissions and continuing to provide low-cost power here in the U.S.
So we really got a lot of positive things on that front and we expect that to continue. On the residential and commercial side, demand was actually up 5%. And so I think that surprised a lot of people in the quarter as well. And even the export market comprised, primarily of LNG shipping in Mexico pipeline exports was up 11% on a 2Q to 2Q basis.
Of course, LNG exports have diminished significantly from the first part of the year, but there are positive signs emerging and the number of cargo cancellations have begun to diminish as you get into looking at the third quarter lifts, and particularly in September now.
The Mexico pipeline exports have been on the rise and are expected to continue, as pipeline infrastructure that’s reaching further down into Mexico are now complete and will soon begin to utilize supplies from the U.S. directly by pipeline, even into areas where Altamira LNG was the typical supply there. So a lot of good things going on there as Mexico continues to bring in natural gas to replace more expensive power generation in their markets.
On our own gas transmission systems, volumes are up 8% in 2020, on average, compared to the three-year average, so a lot of moving parts there. But we continue to see those volumes and certainly on our – on a 2Q to 2Q basis looking at our contracted capacity, of course, and that’s important to us, because that is actually how we get paid on our transmission systems.
Now as we move on to Slide 5 and look at the production update and really pretty simple story here on the supply side. You can see the overall Lower-48 wellhead production in the second quarter of 2020 declined slightly versus 2Q of 2019 to about 0.3%, again, pretty flat. But Williams wellhead gathering actually increased by 3.6%, and that was despite the shut-ins in places like the Eagle Ford and the Gulf of Mexico.
So we expect this to continue to be the story in a wide variety of market conditions, as the low-cost supplies will be the last off and the first to be called on to meet growing demand. We have focused our G&P business with this principle in mind and we’re really excited about the way our gathering and processing business is set up for the next several years here.
Looking into the third quarter, we are seeing no exception, as gathering volumes continue to grow here in July, and our deepwater volumes, as you heard from John, have fully rebounded.
I’m going to move on now to key investor focus areas. And so here on Slide 6, we take a look at these key areas for investors. Our business is durable, because we have the right strategy, the right assets, and we contract our business in a conservative manners that can withstand the kind of commodity upsets that we’ve witnessed here in the second quarter.
Looking first on the durability and from a commercial perspective, our premier gas transmission assets serve as critical components of the nation’s natural gas grid and are driven by a long-term demand for capacity by the major utilities in the densely populated areas.
Our transmission business has fully contracted cash flows with no commodity or volume exposure. And it is important to remember that when it comes to our pipeline business, it is the available capacity that we sell. Therefore, we are not dependent on throughput or volumes.
We contract with high-credit quality customers, primarily utilities and power producers. And by the way, when we speak about credit, we have continually said that we do believe credit is very important for the long-term long haul pipeline contracts, and we have always held this out as a principle of contracting in the long haul business.
In the G&P business, we protect our cash flows by providing services that are essential to the monetization of the reserves in the ground and by owning the infrastructure back to the wellhead in most cases. We also have a diverse portfolio of basins and customers within our G&P business that gives us the ability to withstand a lot of change – individual changes that go on amongst our producing customers.
Additionally, most of our contracts are fixed fee and do not vary with the price of the commodity or basis differential. And that is why you’re seeing such steady and predictable cash flows continuing, despite a very difficult commodity pricing environment here in 2Q.
Producer bankruptcy continues to be a hot topic in the Midstream sector. And, of course, Chesapeake recently filed for bankruptcy. I would note that despite there being a large number of long haul pipeline and processing contracts being listed by Chesapeake for rejection, none of our contracts have been slated for rejection. And that’s primarily due to the fact that we provide this essential service back to the wellhead.
In fact, we see opportunity in the Chesapeake bankruptcy process to strengthen our relationship and expect restructuring to give Chesapeake the flexibility to navigate the fast shifting market and put these basins William serves in a healthier position for growth.
So Chesapeake has got a great position in both the Bradford County, PA, as well as in the Haynesville, and we are well-positioned to serve the growth coming out of those basins as that dry gas gets called on here over the next couple of years.
Looking on the financial side, let me start out by saying that despite an excessively high yield, it’s now over 8%. There is no reason need or intent to reduce our very well covered dividend. We grew it by 5% this year and we still expect our coverage to be 1.7% for the year. In fact, in addition to the coverage on our dividend, we also expect to more than cover our growth capital this year.
This free cash flow generation will continue to improve credit metrics. And in the quarter, we saw our net debt to EBITDA actually go down to 4.31 times, really hard to find anyone improving their credit metrics more consistently than we have and especially in this environment.
Turning quickly to guidance. Despite the turmoil in the space, we’re holding guidance on the profit side and reducing it on the spending side. On adjusted EBITDA, we still expect to land in the lower-half of the range, but our outlook has improved since our last earnings release.
On DCF, we’re still forecasting the midpoint of the original range. But as you will note through the second quarter, we are pacing ahead of the midpoint. On growth CapEx, we’re reducing from the original range of $1.1 billion to $1.3 billion, down to $1.0 billion to $1.2 billion and that, of course, is providing further support for additional free cash flow generation and we have derisked most of the major projects for the year.
So great performance by our project execution teams and this is one of the key drivers for the reduction in our CapEx. And with the risk reduction, we’re actually headed towards the lower-end of even this new range. So great job by our teams out there of continuing to control costs and execute on our projects in a difficult environment.
Turning to sustainability and how we think about that at Williams. Sustainability grounded in sensibility is nothing new here at Williams. Over long-lived – operating this long-lived infrastructure requires focus on long-term sustainability. Our continued focus on sustainability delivers immense value that is well aligned with the interest of long-term shareholders.
Our 2019 Sustainability Report was published on July 27. And this report really provides a very transparent view into the actions we are taking to balance the dual challenge of meeting increasing demand for energy, while reducing emissions and environmental impacts with practical and immediate solutions.
More than 41 – and one of the highlights that I would point to you in there that I’m really proud of our operating teams for being so focused on is that, we’ve reduced our reported methane emissions by 41% since 2012. So really nice job by our teams on that and everybody is proud of what we’re doing to continue to do our part to improve the environment.
And now turning to look at growth. Lots of concerns expressed about the difficult permitting environment that exists. Of course, for Williams, this is a double-edged sword. Our pipes and right-of-ways are positioned to serve some of the most densely populated areas.
And as a result, we have the ability to expand these systems at much lower cost and with much less environmental impact that greenfield projects would present. Of course, this gives us tremendous advantage and provides us with unique growth opportunities at returns that can offset the risk associated with this difficult permitting environment.
Looking at the quarter, despite the unfortunate decision that came out from New York on NESE during the quarter, we had terrific execution across the rest of our project portfolio. In fact, we’re now completing the final tie-ins on our 193-mile Bluestem NGL pipeline extending through Kansas and Oklahoma. And our 42-inch pipeline loop on Transco, along our Transco system for the Southeastern Trail project in Virginia, was completed and placed in service as well.
So great work by the teams overcoming a lot of restrictions due to COVID. But really learning to work in a different way and continuing to deliver our projects on budget and on time. We also – on the G&P side, our Salem Compressor Station, which is in Ohio, was expanded in the dry Utica to meet a customer’s accelerated schedule needs.
So a lot of great drilling success by Encino in the dry Utica and we’ve been working really hard to keep up with their expansion needs out there and really great to see them being successful. And our team is doing a great job of keeping up with that success.
We also received a FERC Certificate for our Leidy South project in Pennsylvania. So really excited to see that project moving along. And Regional Energy Access continues to progress, and we are dusting off the plans as well required to help serve the ACP, Atlantic Coast Pipeline load that remains in the Mid-Atlantic.
So we’ve always been extremely well-positioned to serve that load. And we’re now dusting off some of the original plans that we had. So we think that presents an opportunity, not – certainly not in the near-term, but over the long-term, presents continued growth opportunities along our transmission system.
Taking a look at the growth in our gathering and processing business. First of all, the G&P business is meeting our expectations for the year. And we’ve got great performance out of the Northeast G&P footprint, both on a volume – keeping up with the volume growth out there, as well as cost controlled by our teams out there. So really great operating performance.
Our low-cost basins provide predictable cash flow and continue to position us to grow in a wide range of supply and demand scenarios. As I mentioned earlier, we do believe being in the very lowest-cost – the very low – lowest-cost basins and being in the right spots in those basins is going to be a differentiator for us as we’re moving into these low commodity prices, both on the oil side and as we continue to see gas demand continue to increase.
The most economic gas supplies, we think, will come out of places like Susquehanna, Bradford Counties in Northeast PA, the Dry Utica, the Southwest Marcellus area and the core Haynesville. Our teams continue to tie-in new production and expand compressor stations just like clockwork in both the Northeast and the Haynesville. So you don’t hear about a lot of those projects, because they don’t hit the major products radar screen, but a tremendous amount of great work going on by our teams out there keeping up with that growth.
In the Deepwater Gulf of Mexico, we have really a unique set of capabilities and very well-positioned infrastructure. And we are continuing to win a lot of new business in the Gulf. Latest that we reported on was the LLOG Taggart tie-back. With Taggart, we now expect four expansions – major expansions to come online in 2022 through 2024. And those projects, we estimate somewhere around $300 million of EBITDA just from those four projects and the majority of that will come on into 2024.
But even beyond the big sizable package that you hear about, we continue to build a string of base hits. And now in addition to Taggart, we signed up two other new deepwater packages that will deliver ahead of these larger plays. And in the 2Q, the latest that we’ve contracted four were Fieldwood, [ph] Katmai, Prospect, as well as LLOG Spruance on our discovery system, so really great work going on by our teams out there.
So in a move to close here, we’ve intentionally built a business that is steady and predictable. And this quarter was a chance to show just how durable this business can be against a number of headwinds. Our natural gas focus strategy positions us well to capitalize on continued natural gas growth.
Our existing transmission infrastructure offers growth advantage, as well as durability of cash flows. And our low-cost basins provide predictable cash flows and position us to grow in a wide range of supply and demand scenarios.
We remain bullish on natural gas demand growth, because we recognize the critical role natural gas does and will continue to play in a clean energy economy. Thanks for natural gas. The U.S. continues to see significant reductions in CO2 emissions, along with lower consumer utility bills, and this has enhanced the opportunities for investment in renewable energy.
And finally, I’d be remiss if I didn’t close my remarks by acknowledging the tremendous efforts of our entire workforce who continue to do their part to ensure the delivery of natural gas to American city – cities and communities during the COVID-19 pandemic.
These efforts are frequently overlooked by the general public, who often take for granted a highly reliable and safe energy infrastructure that enables our everyday lives and jobs across our great country, and I’m extremely proud of our employees for their efforts to keep our operations running smoothly, while also going the extra mile to keep themselves and their coworkers safe and healthy.
And with that, I’ll open it up for your questions.
[Operator Instructions] Our first question comes from the line of Jeremy Tonet with JPMorgan. Your line is now open.
Hi, good morning. Just want to start off with, I guess, producer activity across your footprint here. It seems like natural gas has rebounded a bit and commodity prices coming up a bit here.
So just wondering if you could give us a flavor of what you’re seeing across your G&P footprint there? Do you think that the West could tick up again quarter-over-quarter that was certainly a better showing there than what we expected? So any color, I guess, on producer activity across your footprint would be helpful?
Hi, good morning, Jeremy. This is Micheal. We are seeing some activity there across all of our dry gas basins, where producer customers are expecting higher prices next year and we’re seeing that in the forward curve as well.
You’ve seen probably some of the comments from some of our customers that they’re being cautious, I think, with what they’re saying, but they are prepared to participate in a higher-price environment. And we would expect to see that not only in the Rockies, but in the Northeast PA and in the Haynesville.
We’ve even seen some pretty decent activity in the Barnett with some workovers there and some new production coming on just from some wells that had been underperforming. So they are anticipating and taking advantage. It looks like a potential higher-price environment next year.
Got it. That’s helpful. Thanks. And switching gears, it seems like more of the utilities are kind of running test pilots with regards to hydrogen. And granted, it’s probably pretty later data at this point. But just want to see if you had any thoughts as far as hydrogen blending, if that is something that Williams could play a role in going forward? Or any thoughts on this topic would be helpful? Thanks.
Yes, Jeremy, great question, and thank you. We have several projects right now, where we’re bringing in renewable gas from dairy operations and from waste areas. And so we are working. We’ve got a lot of them already online, and we’re continuing to work on those projects. And I would say, those are – will be obviously ahead of hydrogen in terms of coming on, but we do see a lot of investment opportunity around that.
Also, on the hydrogen front, certainly, we’ve heard the message loud and clear from places like New York about the political support for decarbonization, and we think that presents a great opportunity for us at Williams to invest with our customers in projects like that.
And so we certainly are interested in doing that and think we’re extremely well-positioned, given our distribution network into those densely populated areas. We think we’re extremely well-positioned to be able to take advantage. And especially as renewable – excess renewable power becomes available and converting that to hydrogen as a form of energy storage, we’re extremely well-positioned to take part in that.
And as you’ve seen on the solar front, we’re certainly interested in making investments where they make sense in and around our pipeline systems and to take advantage of investments in renewable opportunities.
And so we’re no stranger to it. The team has done a great job of picking up new opportunities like that. And Chad Zamarin and his team have continued to look into opportunities like that. And I think that’s – nobody is better positioned for that than Williams, frankly. So we look forward to continuing to look into those opportunities.
That’s a very helpful color. Thank you.
Our next question comes from the line of Colton Bean with Tudor, Pickering & Holt. Your line is now open.
Good morning. So, Alan, maybe just to follow-up on that on the solar initiative. How do you see that playing out over the next five years or so? And what would you need to see to evaluate renewables as a revenue driver versus primarily cost savings?
Yes, I’m going to have Chad Zamarin to address that for you, Colton.
Sure. Yes. No, I think one of the great things about our position is that, we don’t just view renewable investments as a cost savings opportunity. We do see them as good accretive investments and solar is one of those examples. I think we expect to invest somewhere between $200 million to $400 million over the next few years in solar projects that are immediately along our footprint.
Now, we will likely have partners in those projects in order to optimize the way that gets installed and optimize the value that Williams can capture. But I would just say, Alan mentioned, we’re – we’ve got a fairly good pipeline of opportunities on the solar front. Alan mentioned, we have existing RNG projects coming into the system. We have a pretty good line of sight towards project, add additional dairy farm, landfill projects to our system, where not only we can invest in that upstream opportunity, but we can build the infrastructure to bring that renewable gas into our main line systems.
And then just as a follow-up on the hydrogen front, I think, anywhere where we see, if there will be an opportunity to create value along our pipeline footprint, I think, no one is better positioned than Williams. When you think of our footprint up into the Northwest and our footprint along the Eastern Seaboard and up into the Northeast, I think, we’re very well-positioned to capture project opportunities that add value and do create revenue generation opportunities.
And so I think it’s early days. But I will tell you that we are very focused on that part of the business, because we truly believe that natural gas is part of the solution for how we can invest further in renewables in the United States. So I would expect that focus to continue and we’ll continue to find opportunities over the next several years.
Great. I appreciate the added detail there. And just switching over to the capital front, I think, we’ve seen a few Northeast producers reference a maintenance case for 2021. So I know great preliminary, but any expectations for what WMB’s capital needs might look like in a flattish volume environment?
Well, I would just say we continue to see growth in the Northeast. And I think, as Micheal mentioned, it’s largely dependent on the forward curve, but we do have a lot of producers that are looking to take advantage of that.
And so I would just say, the growth is going to have to come from somewhere. If we don’t see an oil price recovery, we’re going to – there’s going to have to be replacement of those volumes, as well as continue to meet demand growth. It’s pretty amazing if we look at how low LNG exports are and yet our demand for the year has still grown.
And so if we were enjoying that LNG – a typical LNG demand, we would really have the outstripping right now and the market would be turning the other way pretty quickly, I think. So said another way, I’m not sure I would agree that we’ll see flat volumes and certainly don’t see that coming out of the low-price basins, like the Northeast Marcellus and the Haynesville and the dry Utica.
So – but if we did see that, I would just say, our capital has gotten lower and lower and lower in the Northeast, because our systems are very expanded right now. We’ve done a great job of that. We are looking at a couple of expansions, as Micheal mentioned, that are pretty sizable, but that’s in kind of the planning horizon right now.
But if we do see flat, there’s just not a whole lot of capital demand for the Northeast. And so just because our systems are already covering such a wide swath of the acreage that’s dedicated to us something.
Okay. I appreciate it, Alan.
Our next question comes from the line of Gabe Moreen with Mizuho. Your line is now open.
Hey, good morning, everyone. Alan, maybe I’ll bite on the dusting off the plans, given the APC’s demise. Can you just talk about kind of future strategy there? Are these smaller bolt-on projects? Is it something that would be more sizeable and larger capacity?
Well, I would say, we’re – those are obviously going to be customer-driven there. And we certainly are well-positioned to work with the customers to help meet those growing demand with the two laterals, both the main line that goes through Virginia there and with sizable capacity to deliver, as well as the two laterals, the Cardinal line and South Virginia laterals that stretch into those markets. Nobody is better positioned than we are to expand that.
And originally, I would just say, we – we’re pretty certain that expansion alternatives that we had there were a very low-cost. And the primary reason for going to ACP in that case was the benefits of having another major system in the area for liability purposes. But we think with the pressure on cost and the conflict, we’re confident we can maintain that reliability that we’ve always provided for that area, but at a much lower cost.
And so I would just say, we’re working closely with the customers in the area to look at their demand requirements. And we’ve got a great relationship with the customers in those markets, and we’re going to look to tailor our solutions to fit their needs. But in terms of the existing right-of-way, the existing capacity, the ability to expand those debt capacity into those markets. And they goes without saying that nobody is better positioned than we are to help serve that.
And we can do it – importantly, we can do it on an incremental basis. And so said another way, we don’t have to build all the capacity all at once. We can do that over time. And, of course, that’s a huge advantage when it comes to cost efficiency and return on capital to be able to expand those systems as the demand needs, of course.
So Micheal, anything you would add to that?
I would just say, the other aspect that we have that Alan just commented a bit in regard to our existing systems. Building on those brownfield systems is a much lower environmental footprint and environmental impact. And we think that’s something that will carry today as well in regard to these incremental expansions that we can bring to those customers in that area.
Thanks. And then maybe if I can ask also, it seems like ethane recovery has ticked up a bit. I’m just wondering what you’re seeing on your systems out there in the West, whether that’s been maybe a source of a little upside and if it continues, whether that could mean improved economics out of Bluestem?
Yes. We certainly are seeing ethane recovery continue out there and that is boosting volumes in the area. So you may have seen in our OPPL volumes, we’re actually down for the quarter. But that’s just because we had a customer that chose to take their volumes off and pay us for that volume efficiency rather than ship.
And so that – so said another way, while the volumes were off a little bit there, the revenues were not off from that. And so – but we do see expanded opportunity, as ethane recovery comes in. We’re seeing the Ford market is actually continuing to show margin for most of the rest of the year on ethane. And so, given our limited appetite for commodity price risk, we’re taking advantage of that as we see that forward market present itself for taking advantage of that.
Great. Thanks, Alan.
Our next question comes from the line of Derek Walker with Bank of America. Your line is now open.
Good morning, everyone. Thanks for the time. Maybe just a couple of quick ones for me. Alan, you talked about addressing some of the counterparty risk and you obviously talked about Chesapeake actually presenting some potential opportunities around some of the restructuring potentially benefit in Bradford and Haynesville.
Just want to see if you can provide a little bit more color around some of the dynamics there? And then I know Chesapeake has some exposure in Eagle Ford, or you have exposure to test being in Eagle Ford? Can you just talk a little bit more about some of the outcomes you might see in that basin? Thanks.
Yes, this is Micheal. I guess, I’ve walked through the three major basins that we have exposure with Chesapeake and the Bradford. We have a cost of service agreement there with them. It’s a very low-cost rate that they enjoy there. It’s a cost of service agreement, that’s actually working very well for both us and the customer. And I would not expect, obviously, any pressure there with the continued growth that we’re seeing.
Haynesville, a very similar situation. We expect continued growth out of the Haynesville. We have been working with a number of customers in the Haynesville to offer incentive rate there where it makes sense to incent some additional drilling whenever the prices were lower, and we think there’s an opportunity to continue that if prices don’t rebound. But right now, the strip looks more favorable for that dry gas basin in there.
And in the Eagle Ford, we have a substantial footprint there with Chesapeake as well, and we move a lot of volume. Those volumes are back to where they were a pre-COVID situation for the most part. And that’s the basin that’s obviously exposed to NGL prices, as well as condensate and oil prices.
And as those prices are expected to rebound with picked up demand, we would expect the Eagle Ford to be another area that we would continue to see some growth in the future with Chesapeake. So those three major basins, we have Chesapeake. We don’t see a worry on our horizon in regard to continuing to see good economics for the customer there, as well as for our Midstream business.
And as far as the incentives in the Haynesville, is that – would that be on an incremental production? Would that be – what type of rate would that look like compared to what you’re currently charging in?
Yes. That is on incremental production only. We’re not discounting, obviously, any PDP volumes that we have going on our systems today.
And I would add to that, where we are doing that the only place we would agree to do that is where we don’t have any capital investment. So this would just be incremental drilling, where there’s no capital required on our part. And so we love that business to have the incremental flowing volumes and have that revenue grow without having to spend any well-connect capital out there.
And so that’s a great opportunity for both the us and the producer. If prices firm out there a bit, then there won’t be a need to do that and we won’t. But if prices are low enough, that’s a great way for us to keep the cash flows building without spending new capital.
I appreciate that. Maybe just a follow-up on the deepwater. I want to make sure I heard some of the numbers right. I think from the slide and based on guidance, I think, you’re running around $450 million of EBITDA on deepwater, with $300 million expected from the four major projects.
Should we think of that base EBITDA as being fairly flat? Or is there some sort of impact from the actual decline rate? So just trying to get a sense of that $300 million that you referenced is going to be incremental or potentially offsetting some natural decline?
Yes. That’s a great question. I mean, obviously, the deepwater business does decline over time and I’m not confirming the $450 million here. But let’s assume it’s in that range. Normally, you would expect declines. The good news is that we’ve continued to be tying in so many single base hits that I’ve referred to earlier, that that’s tending to offset that normal decline ahead of those bigger projects.
So will it stay actually flat? I would say, if we start counting that those projects in, then the answer would be no. We would have some decline underneath that. But so far, the the environment is really positive out there, and infill that’s coming from producers in and around our assets is offsetting those declines.
And so this would be incremental, but that is dependent on those continued tie-in. So obviously, there – we don’t have contractual protection from the declines out there. I guess, I would remind you.
One thing – this is John Chandler. One thing I’d add to that, too, is we do have a couple of more quarters of deferred revenue step downs related to a big platform that customer paid for several years ago. That pretty much stabilizes at the end of this year and the step down stopped, but we’ve got another probably ZIP code $50 million of step downs between the next two quarters in deferred revenue in the deepwater.
Thanks, John.
Got it. Thanks, guys. I really appreciate it. Thanks, Alan. Thanks, John. Thanks, Mike. That’s it from me.
Thank you.
Our next question comes from the line of Shneur Gershuni with UBS. Your line is now open.
Hi, good morning, everyone. Most of my questions have been asked and answered. Just two clarification questions, if I may. The first one is just with a lot of focus on the election these days and sort of an expectation out there that tax rates could go up, would you be in a position in from a Transco perspective to be able to increase rates as a result of higher tax rates? Or does the recent settlement that you entered into prevent that from occurring?
No. I mean, we – obviously, as part of our rate settlement exercise, we do build in tax rates. Now we have to wait for our next rate case, obviously, to push that through to our base rates. So yes, clearly, higher tax rates would benefit us in the form of higher rates in the future on the rates that are subject to our rate negotiate or to the rate case.
Now again, remember, on our Transco system, about 50% of our rates are negotiated. So obviously, it wouldn’t have an impact on that. But certainly, the rate – part of our rate case and rate base is subject to an assumption on taxes – the tax rates.
Certainly, it’d be beneficial almost in whole the Northwest Pipeline, right? Because we don’t have the negotiated rate element of that in Northwest Pipeline. So about half of Transco and nearly all of Northwest Pipeline would benefit from that.
So that makes perfect sense. Thanks, guys. And maybe just one clarification with respect to your guidance commentary today. If I sort of think back to when you last updated us formally second quarter was supposed to be the most challenging quarter for 2020. Decent – pretty strong quarter. Officially, your guidance commentary hasn’t changed. But in your prepared remarks, you said that things were looking more promising.
So when I sort of see no change to guidance, it sort of implies the second-half might actually be worse than 2Q, or is this just more nuance that you’re just not formally changing your guidance at all, because nothing has changed materially? Is that kind of the way to read it?
I was wondering who was going to raise that, Shneur. Thank you. I would just say that, yes, we had a good quarter. We’ve had a good first-half of the year. You can see our costs are extremely low. I think, we want to make sure that we’ve got room in there for things like we’re going into to a more intense part of the hurricane season. And so we – and we certainly plan on things like that disrupting our business.
So, yes, I think we’re extremely well-positioned right now on guidance to outperform on that, but there are always things that can go against you and – in – on both the cost side, as well as disruptions like hurricanes or another price setback on crude oil that might cause shut-ins in the deepwater or in other oil basins as well.
So I would just say, we’re wanting to make sure – given the uncertainties in the market, we’re wanting to make sure that we’ve got room here for the balance of the year, as it relates to guidance.
So to paraphrase, an element of conservatism is basically baked in there. Is that kind of the right way to read it?
Well, yes. But I also would say that, it would be rare that we wouldn’t have some kind of Hurricane impact in 3Q as well, and it’s a question of how big that is obviously? And I would say, I think, it’s not necessarily conservative to think that, that we might have more pricing impact rebound here. So I think, yes, we have room for those kind of things. You can say that’s going to – if you want to claim that’s conservative, then I would say that factor.
And, Shneur, this is John Chandler. I just say one other thing. I think our teams do a fantastic job of forecasting. But I’ve got to tell you in this COVID environment, it’s tough looking at cost, and I’m talking about our field people actually forecasting as well. We’ve done a tremendous job at cost savings year-to-date.
I have a suspicion that’s going to continue. It’s hard for our folks to forecast that with any level of accuracy. I mean, we don’t even know when people could come back in the office that – with the COVID. And so if you think about somebody in the field trying to plan for maintenance or just even hiring people, that’s not an easy thing to do. So we’ve been very successful in cost reductions. I suspect that will continue, but I don’t imagine that’s fully baked through our forecast as good as we’re going to do is my guess.
No, that makes perfect sense, guys. I really appreciate the color and have a safe day.
Thanks, Shneur.
Our next question comes from the line of Jean Ann Salisbury with Bernstein. Your line is now open.
Good morning. Warren Buffett’s purchase from Dominion said a marker in the space, but I’m not sure it was a great one at 10x for mostly demand coal gas assets. Did you compare and contrast how you see Transco and Northwest Pipeline compared to those assets, especially Dominion Gas, which was the bulk of the purchase?
Yes. I’ll take that, Jean Ann, and I think Micheal has got some comments on that as well. First of all, I think, it’d be hard to compare the quality of those assets up against ours, both in terms of growth and headroom in the markets and the network benefits that our systems have.
But I also would remind you that there were things like on the Cove Point facility. There was a step down coming there, because they were still getting paid for the gasification side of Cove Point. Of course, we used to own that. So, we understand those contracts. And so to not take that into consideration, I think, is something you certainly wouldn’t see the Buffett organization do to not take that into consideration. And so I think anytime you’re looking at price points, you have to get pretty specific, especially when you have major contract shifts like that in a business like that.
So Micheal, I don’t know if you have some additions?
Yes. I think I would just add on the amount of debt that was taken on there as part of reflective of the multiple that was paid as well. So I think you have to take that into consideration, as Alan said. And I don’t think there’s a comparable system for the Transco system out there right now, and that’s certainly not a good marker for any of our transmission assets, especially the Transco system today.
Great. That’s helpful. Thank you. And just as a quick follow-up. With the completion of Mountain Valley drive increased potential firm transport opportunities on Transco, it seems like it’s actually getting pretty close?
Yes. We certainly are rooting for MVP and would provide supply at a point, where we could continue to serve market expansions. And so we we certainly would love to see that get completed, because it does bring supply right into a critical point of our system that allows our network to continue to expand and serve expansions along our system.
Great. Thanks a lot.
Our next question comes from the line of Tristan Richardson with SunTrust. Your line is now open.
Good morning, guys. I appreciate all the comments today, particularly around the update on 2020 capital plans. As you look out further, as we think about capital towards Bluestem and Southeastern Trail winding down, and Taggart and Leidy South and some of the renewables projects ramping up, is it possible you could see the 2021 capital look very similar to 2020?
Yes. I think it’s a little bit early to call that for a number of reasons. But, yes, I – we don’t see right now that being having a whole lot of load against it. Regional Energy Access, obviously, was a little bit later in the cycle and the well investment for shale will probably start more seriously towards the end of 2021 or end of 2022. And both of those projects would drive our capital back up to the $1.5 billion, $2 billion range. But – so I would just say, so it’ll be somewhat timing dependent on those projects as to how quickly we started investing on those projects and drive that capital up further.
That’s great. That’s all I had. Thank you guys very much.
That’s all the time we have for questions today. I will now turn the call back over to Mr. Alan Armstrong for closing comments.
Okay. Well, thank you all very much. I do have one note that I’d like to recognize somebody here at the company. It’s very difficult to do the typical celebrations that we do for retirement.
But Ted Timmermans, who has served the Williams Company for over 41 years and – has referred as the – was our Chief Accounting Officer here at Williams for 15 years. This is his last effort for the quarterly call, and John Porter is taking over the Chief Accounting Officer role and have been a great transition that’s gone on there, much in keeping with the way Williams does business, very steady hand on that.
But I certainly want to just say a huge thanks to Ted Timmermans for all of his great service to the company and for the the standards of excellence that he has always established in our accounting efforts here at Williams. And we were very fortunate to have his leadership here at Williams for a number of years. So, Ted, thank you very much, and we wish you the very best in retirement.
And with that, we thank you very much and we appreciate to continuing to share the good story here at Williams. Have a good day.
That concludes today’s conference call. You may now disconnect.