Williams Cos Inc (WMB) — Q3 2018 Earnings Call Transcript

Thanks, Todd. Good morning and thank you for your interest in the Williams Companies. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include press releases and related investor materials, including the slide deck, that our President and CEO, Alan Armstrong, will speak to you momentarily. Joining us today is our Chief Operating Officer, Michael Dunn; and our CFO, John Chandler; and Chad Zamarin is with us as well. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks and you should review it. Also included in our presentation materials are various non-GAAP measures that we've reconciled to generally accepted accounting principles. And these reconciliations schedules appear at the back of today's presentation materials. And so, with that, I'll turn it over to Alan Armstrong.

Great. Well, thank you, John, and thanks everybody for joining us this morning. We're pleased to review with you a very strong third quarter for 2018. We demonstrated continued, predictable and sustainable growth in all of our key financial metrics, and we also think this is a great platform for the more dramatic growth that has just begun. But before we get into presentation, I want to take a moment to officially welcome our new Senior Vice President and Chief Human Resources Officer, Debbie Cowan to Williams. We're really excited to have such an outstanding leader join us and join our executive officer team. Debbie's an accomplished human resources professional coming to us from Koch Industries. And we're excited to add another great member to our very talented team here at Williams. I'll pause briefly now and point to our cover slide which highlights briefly some of the many exciting construction projects that are going on in the company right now. Honestly, it's kind of hard to pick because we have so many projects going on, but here on the left-hand side is a photo of the 200 MMcf a day Fort Lupton plant III gas processing plant. This is the third train at this Fort Lupton site and it's expected to be in service by the end of this year. The photo on the right is from our Oak Grove complex in Oak Grove West Virginia where you can see the construction of both TXP2 which is well underway now, as well as TXP3 which is in the background there. So, it's an exciting time for Williams now. The robust domestic natural gas demand growth is fueling demand for our fee-based natural gas infrastructure services. Natural gas usage is growing across almost all categories and has proven to be a good companion fuel for renewables, as we saw demonstrated this summer. In fact, this summer was a great example of the kind of demand growth we're seeing as net power generation was up by 4% or about 15,200 gigawatt hours. But natural gas-fired generation was up 17,300 gigawatt hours. So, not only did natural gas capture all the growth during the summer period, it also made up for coal and hydro losses as well. So, again, it actually outstripped – got all of the growth and then some in the space and we're continuing to see that big pool. In fact, if you really study the EIA numbers that just come out recently, you'll see that natural gas has been more than holding its own even in the face of large investments in renewables and currently accounts for over 57% of the new generation capacity that's currently in late-stage development. So, it's really interesting to see this emerge and see natural gas starting to become base load now as well as following load as renewables come online. And so, a lot of new renewables, but actually natural gas is outstripping that growth. So, let me just list the other things we're going to talk about today here real quickly. First off, we'll spend a little time providing perspective on some of the key investor focus areas for Williams. Then, we'll discuss the key drivers behind our financial and operational metrics for the third quarter and year-to-date. We'll highlight the major project contributions in the third quarter and provide an update on the other key achievements that have happened during the period. I'll wrap up by revisiting how WMB stacks up as an investment against the broader U.S. market. So, let's move to slide 2 and look at some of those key investor focus areas. First of all, we enjoyed a great quarter with many highlights. But before we get into the details of those results, I want to discuss the strong fundamentals that insulate us from many of the investor concerns in this broader space. So first of all, we do get a lot of questions on our views of Northeast G&P growth. That's our fee-based gathering and processing business in the Northeast. Atlantic Sunrise has opened up new markets for Marcellus producers and that is now driving even more accelerated growth in our Northeast G&P business segment. There's a strong demand pool from pipeline commitments. As an example, on the day that Atlantic Sunrise was placed into service, which was October 6, Northeast Leidy gas prices rose from $1.20/Mcf to $2.70 per Mcf. Now, that by – in just one day, wouldn't tell you a whole lot, except that gas prices have continued to drift upwards now for the balance of October. So, probably, in my career, that's been the most significant change that we've seen from any major piece of infrastructure changing an entire basin, not just the Leidy gas but also Dominion South and the Tennessee gas price as well. So, where is the Northeast G&P headed? Right now, we're wrapping up our annual budget cycle where we've worked closely with producer customers to understand the very specific project needs that they're going to have over the next two years to meet their own business plan. This is a very detailed well-by-well work which, over the last few years, has led us to internal forecasts that have been very accurate. For example, through September of 2018, we are within 2% of plan expectations and that's on over 7 Bcf a day of operated volumes with a number of different drivers going on. We do think we have a very good handle on the drivers and right now our forecasting work, along with the minimum volume commitments that continue to build as we build out our facilities, tells us that we should expect steady growth in our Northeast segment amounting to a volume CAGR of 15% from 2018 through 2021. Additionally, we expect to realize significant operating margin uplift during this time which should drive even higher overall growth in EBITDA than that 15% CAGR. As evidenced of our improving operating margin, you can see it in the third quarter 2018 results versus third quarter 2017, where the EBITDA per Mcf, which is a measure we've often pointed to in our Analyst Day, has now increased during that period again, 3Q 2017 to 3Q 2018, by 8%. So, we are seeing that come through as we had forecasted. As our volumes build, we're going to see more and more of that benefit. Secondly, we field questions about our overall EBITDA growth beyond 2019. While we're not providing specific guidance beyond 2019, I think we can be pretty clear about our general expectations in this area. Our guidance for 2019 reflects approximately 10% EBITDA growth over 2018. We feel comfortable sharing our expectations of approximately 5% to 7% EBITDA growth on the longer term. Of course, with new projects, that growth could improve further but we have great visibility as we look at our five-year planning cycle. What’s more, this growth is steady and predictable because it's based on fully-contracted demand payment projects and our existing fee-based business model that is not impacted by volatile commodity margins. Looking ahead, we have great visibility into continued improvements primarily through capital discipline, and visible earnings growth on a per share basis as earnings across all of our businesses drive that. Next up, let's talk about leverage. There's been significant deleveraging over the last few years and I can assure you that focus will continue into the future as we move toward a 4.2 times book leverage target over the long term. We have been de-leveraging through an asset sale program, not by issuing undervalued equity. And as we all understand, that is going to drive long-term value. Our management team is focused on a very rigid capital discipline. We passed up many opportunities over the last couple of years where the risk-adjusted returns just no longer aligned with our principal focus on improving returns and decreasing our leverage. This focus has also led to creative portfolio optimization strategies like the sale of assets in a maturing basin in our former Four Corners Area at attractive multiples and redeploying some of that capital to the higher growth DJ Basin. In this transaction, we received an over 13 times multiple, highlighting the valuation discount that exists between the public market valuation of our company today and the indisputable market value of even the bottom quartile of our portfolio. The announced sale of Dominion's interest in our Blue Racer Midstream JV that just came out this morning is one more piece of evidence to support this assertion where they quoted that transaction between 14 to 16 multiples. We've definitely heard a lot of confusion in the investment community about this year's FERC actions. The FERC rate-making environment appears to have weighed on the natural gas-focused names like Williams. I want to remind our investors that our Transco rate case was filed on August 31, with an overall increase in rate. An improvement from 2018 Transco rates would be an upside to what we've provided in our 2019 EBITDA guidance. Of importance is pointing out that we do not expect our major natural gas pipelines, not Transco, not Northwest pipeline, and not Gulf Stream, to be impacted by the 501-G process. Finally, we continue to be pleased with our joint venture DJ Basin acquisition. Operationally, the newly renamed Rocky Mountain Midstream is performing well and we are seeing even more growth than we expected. We have sites with permitting underway for greater than 1 billion cubic feet per day of gas processing. Many questions have arisen regarding the Colorado Proposition 112. Based on the incredible importance of the oil and gas industry to the state of Colorado and the fact that this campaign is being run by out-of-state interests, we believe that the measure will not pass, or it will undergo significant common-sense revisions from the Senate legislature if it does pass. We've been in Colorado for a long time, not in the DJ Basin, but in other parts of Colorado. We've seen these kinds of things come up before, and we've always found the state to be fairly pragmatic. We do think it's a very important issue for the state and the oil and gas industry, and wouldn't try to understate that in any way. However, we have seen the state handle these matters in a pragmatic manner over the years. But even if it does pass, I want to make it really clear that 100% of the forecasted wells supporting our growth have been permitted through 2020, and over two-thirds of the forecasted 2021 wells have also been permitted. We feel good about the growth that we see in that area and the proactive effort that the producing customers upstream of us have taken to have their wells permitted. Thanks for letting us take a little time to share our perspective on these key investor focus areas. Let's move quickly to slide number 3 and take a look at the third quarter 2018 results. We see our unadjusted GAAP results in the upper portion of the slide, and our normalized numbers in the lower portion. But looking first at our GAAP net income, we see an improvement of $96 million, increasing to $129 million. This favorable change was due primarily to a $227 million increase in operating income. Partially offsetting this improvement was an increase in the provision for income taxes driven by a valuation allowance on certain deferred tax assets following the WPZ roll-up. Turning now to the adjusted metrics, we can see our adjusted EPS of $0.24 was an impressive $0.09 or 60% increase versus the third quarter of 2017, and adjusted EBITDA grew 7.5% in that period. This improvement was driven primarily by a $68 million increase in fee-based service revenues due largely to Transco expansion projects brought online in 2017 and 2018 and also higher gathering volumes in the Northeast G&P segment. The quarter also benefited from higher commodity margins in the West; however, these were largely offset by the changed accounting practice on revenue recognition. If you normalize WMB's third quarter 2017 adjusted EBITDA for the change in revenue recognition, you would have seen a 10% growth through the same period. At the business segment level, Atlantic-Gulf adjusted EBITDA increased by $49 million in the third quarter of 2018 to $480 million. The improvement reflects a $43 million increase in fee-based service revenues primarily on Transco's Big 5 expansion projects that were placed in service in 2017, along with an additional expansion project placed into service in 2018. Our Northeast G&P segment increased by 14% or $35 million to $281 million, reflecting a $33 million improvement in fee-based revenues due to higher volumes at the Susquehanna and Ohio River systems, and improved operating margins as we discussed earlier, which we expect both trends to continue for quite some time. Now let's move on to slide 4 and take a look at the year-to-date results. Year-to-date net income is down on a GAAP basis by $71 million versus the same period in 2017, even though operating income was up by $320 million. The 2018 net income year-to-date is missing a large gain on asset sales that was recognized in March of 2017 and that really drove that difference. Focusing now on those adjusted metrics, you can see down below, we've had a year-to-date adjusted income per share attributable to Williams of up by 45% compared to the same time period in 2017. Adjusted EBITDA increased by $70 million to $3.44 billion, even after the lost EBITDA from the Geismar plant sale and a $65 million unfavorable impact from the adoption of new revenue recognition standards in 2018. All three of our current business segments showed growth over the period – sorry, over the prior year, driven by a $233 million increase in service revenues due largely to the Transco expansion projects and higher gathering volumes in the Northeast G&P segment. Now, let's move on to slide 5 and take a look here at the tremendous accomplishments and solid execution that our teams continue to deliver in a very predictable manner. We’re very pleased with the recent announcement of the Leidy South Expansion project, which I'll talk a little bit more about here in just a moment. Very recently, the FERC approved the start of construction for our Rivervale South to Market project that will take place primarily in New Jersey. We're targeting the 2019 through 2020 winter season for completion of this project which will help meet the growing heating and power generation demand for the Northeastern customers, primarily in New Jersey and New York. So, yet another fully-contracted, high-return project that we have gotten permitted in very challenging territory. I will tell you it's no easy task, but our teams are very good at it and continue to build a great reputation with the regulators. You may recall we announced our Bucking Horse expansion project with our joint venture partner, Crestwood, in late July. When finished in 2019, this expansion will increase processing capacity to 345 million cubic feet per day to serve growing customer demand in the Powder River Basin. This growth is on top of the growth we are also experiencing in the Wamsutter Basin just to the south in Wyoming. We've already spotlighted our entry in the DJ Basin. That transaction occurred in the third quarter. On October 1, we closed the Four Corners sale for $1.125 billion. The cash proceeds contribute to funding our portfolio of attractive growth capital and investment opportunities. And, of course, that gain on that sale would be recorded in the fourth quarter. We completed the Williams acquisition of Williams Partners on August 10, which provided us with a simplified corporate structure and streamlined governance while maintaining investment-grade credit ratings. Great execution by our corporate teams on that effort. Most of you know that we placed the Atlantic Sunrise project into service on October 6, awarded the International Association for Public Participation's Project of the Year Award. That's a prestigious award for projects that require public participation and engagement. Atlantic Sunrise segues into an impressive list of 2019 drivers as we'll have a full year of revenue from ASR, the 1.7 Bcf per day Transco expansion. This increases Transco's capacity now to 15.8 Bcf per day and provides $35 million of revenue per month just on that asset, not including the upstream gathering revenues that will flow behind that. This project plays a role in debottlenecking the Northeast where we already hold the largest gas gathering position across the Marcellus and Utica Shales. This increase in gathered volumes is facilitated by gathering and processing expansions that are taking place right now. We have another Transco expansion that will enhance our customers' LNG export needs. We are closing in on placing the Gulf Connector project into service much earlier than originally planned. This project is designed to deliver about 400,000 dekatherms per day to Cheniere Energy's Corpus Christi liquefaction terminal, and an additional 75,000 dekatherms per day of natural gas to Freeport LNG Development liquefaction project, and we're going to be able to deliver those about three months ahead of what our original plans were for that project. Our Norphlet pipeline in Gulf East is expected to be placed into service in mid-2019 and this will deliver results in 2019 and then will be a bigger driver in 2020. That's in the Shell Appomattox field. They have four other fields dedicated to us in that area as well. We have completed our work on the Mobile Bay plant and are ready to take on that gas as soon as they complete their offshore line ahead of schedule. If you look back on our earlier notes regarding this project, you would have seen we were expecting it to come online in 2020. Let's move to slide number 6 and check in on a couple of key projects providing access to new Northeast supplies. When we spoke to you at Analyst Day in May, we referenced two expected Transco expansion projects to provide access to new Northeast supplies. First of all, known as Project Number 2 at Analyst Day, Project 2 is actually our Leidy South project. We have a 15-year commitment with Seneca Resources and Cabot for 100% of the 580,000 dekatherms of firm transportation capacity, which will continue to grow our strategic footprint in the Marcellus, adding to the 62% growth in Transco design capacity since 2013, as well as adding to the already 3 billion cubic feet per day of Transco's Marcellus takeaway capacity over the same time period. We are targeting a fourth quarter 2021 in-service date that will provide attractive returns consistent with the recent Transco expansions. Additionally, Project 1 is very much alive and well. We're awaiting final board approvals from our customers on that project and expect an announcement in the fourth quarter of this year. These two projects keep adding to our string of hits that give us confidence and transparency in our growth for years to come. So, with that update, let's move on to the last slide, number 7, and wrap up, and we'll take your questions. On this final slide, we've recapped many of the key points we've made detailing why Williams is a strong, stable, conservative and growing company. Many of these themes link back to what we've discussed previously in the presentation, so I won't drag you back through all that detail here again. Rather, in summary, as I said at the beginning of the presentation, I am extremely pleased with how the company is positioned right now. Natural gas demand is experiencing strong growth, and the fundamentals continue to build on the backs of low-priced natural gas for demand, which is really going to drive our success. We have experienced strong execution across our irreplaceable natural gas-focused asset base. We have built an earnings base that's highly predictable and not subject to commodity price volatility. We have improved our balance sheet position and we have visibility into continued improvement primarily through capital discipline and visible earnings growth on a per share basis. On the right-hand side of the slide, you can see the very favorable comparison between Williams and the Median S&P 500. We've discussed previously that we anticipate a terrific 2019 with 10% EBITDA growth, and we have a clear line of sight to 5% to 7% EBITDA growth for many years to come. This quarter's strong execution results highlight why we are so bullish about the future and we look forward to returning quarter after quarter, showcasing how Williams is delivering on the opportunities created by our natural gas infrastructure-focused strategy. Thank you for your time today, and we'll turn it over for our first questions.

Morning, guys.

Good morning.

Just as a question here, in your prepared remarks, you sort of talked about the Blue Racer asset selling for 14 times to 16 times EBITDA. You're obviously trading below that. And I'm kind of thinking about your guided dividend growth rate of 10% to 15%. Given that valuation disconnect, has there been any thought about altering your return of capital plans to possibly lower the dividend growth rate and then pursue a share buyback to fill the gap? I'm just curious how you're thinking about these valuation disconnects with your discussions with the board.

Great question and certainly something we constantly monitor and discuss with the board. I would say that we are very focused on deleveraging. And so, I would say that is front and center. But as you've seen, being able to continue to do asset sales at these kinds of multiples drives a lot of value as well and frees up capital for those kinds of things. We certainly constantly look at those opportunities and we think there's a lot of value to be realized in the stock as we consider those various alternatives. But I wouldn't want you to lose sight of our focus on that 4.2 times metric that both the board and the management team are pretty laser-focused on right now.

Is it fair to say that if you were offered a very attractive price, you would consider selling assets as well?

I would say we look at things first from a strategic standpoint. The Four Corners asset really wasn't integrated into our asset base. We didn't see the growth in that business, and it didn't have the kind of operating margin ratio that we typically enjoy there. We certainly look – we'll look at assets like that. We also have a transaction we're working on for the purity pipes in the Houston Ship Channel area that's not strategic to us any longer. I would say it's a combination of the kind of value that we think the assets can build in terms of our overall strategy. As we've proven, we're willing to pull the trigger when we see a valuation upgrade that doesn't damage our strategy.

Now that makes total sense. One last follow-up, an operational-type question. I was wondering if you can discuss what you're seeing in the Northeast regarding producer behavior. You had strong dry gas gathering volumes but also had higher NGL production. At the same time, processing volumes were down. Are we starting to see a shift from dry to wet gas? I'm just curious if you can give us some color around that.

The Ship, I think we're going to see some dry gas volume pick up obviously with Atlantic Sunrise coming on. The wells in Northeast Pennsylvania are so large and can come on so fast that if you're looking at volume, you might see a quicker reaction up there due to the size of the wells and the production. Several of the producers, especially Southwestern, has ramped up their efforts, along with us, putting a lot of infrastructure in the Ohio Valley Midstream area. We're going to see some impressive volume ramp-up in that area as our infrastructure comes online. So, I think we're going to see a pretty balanced approach to both the wet gas and dry gas. We've got to build out our infrastructure to allow that gas to flow, and we’re well on our way to getting that built out right now.

Perfect. Thank you very much. Appreciate the color today.

Thanks.

Thanks, everyone, and good morning. Alan, now that the Atlantic Sunrise is online, how transformational do you see this being for the Northeast G&P segment? You outlined in your prepared remarks that you expect EBITDA growth in the segment to actually be higher than the 15% in volume CAGR you outlined. I'm trying to understand how significant this could be for Williams going forward.

Thank you. We've been investing in the Northeast for a long time, waiting for things to finally get debottlenecked. I don't think anybody has doubted the resource. We've seen a variety of different producer reports come out here in this quarter and earnings season. Much of the production behind our system has been held up for various reasons regarding growth in those areas. Cabot, in our Bradford County, and our Susquehanna County area, literally had no way out of there at a price that made any sense. That has opened up. Even gas in the Southwestern PA and West Virginia areas, while it had takeaway capacity, the pricing hasn’t BEEN all that attractive until more recently. One thing people tend to miss is the amount of acreage behind our systems that have not been drilled. If you look at the density of drilling on our dedicated acreage versus a lot of our peers, you would see that our density is much lower than our peers, partially due to a number of high-priced contracts that have been resettled. There was also the Chesapeake contract that Southwestern secured and we reformatted to allow them to drill in that area. Even in the Utica, Chesapeake was undercapitalized to produce there. Now, we have Encino with the right capitalization to bring that up. So, across these areas, we've been facing those points of resistance, and we’re now seeing them cleared, driving a lot of this rapid growth.

Thanks for that. And within that CAGR you outlined for the volumes, how much CapEx are you assuming annually?

I don't know that we've disclosed that actual number. At Analyst Day, we talked about about $500 million a year for our Northeast investments, and that's ramped up a little bit with the projects that we approved earlier this year at Oak Grove. We see that as a pretty good average there in the Northeast.

Aside from that, a little bit to Alan's previous answer, in the Northeast growth, we're seeing a lot of producer customers that capture market demand that never has to hit the interstate pipeline. Many large gas-fired power plants are being built right on our gathering systems, moving those volumes from the wellhead to these power plants for our producer customers without needing to leave the basin. There’s a lot of growth there for our customers that they’re seizing.

Thanks, Michael. Last question for me. Alan, you stated in your prepared remarks to focus on capital discipline. As you evaluate growth going forward, have your thoughts evolved on the Bluebonnet Market Express?

We certainly see another project that needs to be built there. We see a lot of interest. Chad Zamarin and our team are doing a great job of looking for potential joint ventures in the area, so stay tuned.

Those are my questions. Thank you.

Thanks, Danilo.

Good morning. Just want to build on the topics of portfolio management and leverage here. It seems like in the marketplace there's still a strong preference for getting leverage lower, and I know you have a 4.2-times kind of longer-term target. I’m just wondering what your thoughts are on possibly accelerating that approach given the strong price tag on Blue Racer and the non-core assets, especially since you have a strong suite of growth projects in front of you. I'm curious about your thoughts on selling some more assets and moving that leverage down.

We're constantly looking at that and the opportunities are not lost on us. We really don’t want to damage our future in that process. As I mentioned earlier, we are willing to take advantage of the private infrastructure fund money that's willing to pay higher valuations than the public market does right now. We think that's an attractive vehicle for us. We are serious and very anxious to get down to that debt-levered metric we see out there, so we’re working hard toward that.

That’s helpful. Thanks. I wanted to turn toward the guidance here for a minute. You said you're heading towards the top end of the 2018 guide, but even if you do hit the high end, it seems like it would be kind of flat in Q4 versus Q3. Granted, you have the Four Corners sale, but you also have Sunrise and the G&P upstream providing some nice operating leverage. I'm wondering what line of sight you have to keep that quiet and whether the Q4 guide is conservative or if there are other headwinds.

I don’t think there are any particular headwinds to note. Just a couple of things to consider in that math. We're making room for lower NGL margins which we’ve observed, and that’s not a very big number for us. In terms of what you're talking about, it’s fair to say we are trying to make sure we leave plenty of room there. You could argue we are being conservative. We’ve seen these things swing hard before. Secondly, we have operating cost considerations. Our Asset Integrity program means we’re constantly running tests and fixing things we may find. We want to leave plenty of allowance in our operating budgets to repair things we discover, so we try to leave adequate room in our allowance as we go. Finally, remember that the Four Corners sale also needs to be accounted for in the calculations. I would say we're pretty confident in being at least at the high end of the guidance range.

That's helpful. Thanks. Just to clarify, the 2019 EBITDA guidance being 10% higher—is that relative to the midpoint of 2018 or if you hit the high end, would it be off the high end?

It’d be off the midpoint. I mean, we haven't changed our guidance for 2019. The midpoint there was $5 billion.

Got you. That’s it for me. Thanks for taking the questions.

Yes. Good morning. Thanks for taking my questions. I'd like to discuss leverage for a couple more questions here. The 4.2 times number you're referring to this morning, how did you come to that number? We see targets at 4.0 times or 4.5 times. How do you come to such a precise 4.2 times?

This is John Chandler. We—obviously, in preparing for the WPZ roll-up, we spent a lot of time talking to rating agencies. We have a desire to be a solid BBB, Baa2 rated company. It became clear during those discussions that that meant, on their calculations, using how they do their calculations, that 4.5 times was the target. There is about a 0.02 to 0.03 difference between our bookkeeping, that EBITDA ratio, and how they calculate that 4.5 times. That’s where the 4.2 times came from.

Perfect. Makes sense. Any guidance on how quickly you can achieve the 4.2?

In 2019, we guided to inside 4.75 times. Obviously, in 2020, we’ll see EBITDA growth that will help bring that down further. We'll continue to look for asset sale opportunities and ultimately bring that down further. I don’t want to give you an exact time frame for how we'll get there, but we are focused on that.

Great. It was worth asking. On the DJ, you talked about having all the wells permitted out through 2020 and mostly through 2021. Can you give us any more specifics on what the forecasts are, how many wells you're thinking of?

Good morning. This is Michael Dunn. Right now, we have about 60 MMcf/d of processing capacity installed, and we're working to get another 200 MMcf/d by the end of the year, early 2019. With that online, we would have about 460 MMcf/d of processing capacity in our Rocky Mountain Midstream asset. We expect the first 200 MMcf/d that's coming online to be fully utilized quickly, and that's why we have the Kingsburg facility constructs for mid-2019.

We also expect that we have a little over 800 wells that are already approved looking at 2019, 2020, and 2021.

That's great. You would go forward with all of that, what Mike just talked about, regardless of next Tuesday’s outcome?

Yes. We're certainly watching the way it is treated but for now, there’s plenty of gas waiting for this infrastructure. The near-term construction is required by our producers who are desperate to see it go in. We'll keep an eye out before committing to any further capital—but right now, there’s volume and demand for services for expansions.

Great. Thanks, Alan. That’s all I have.

Thank you.

Great. Thanks. Good morning. Just first, given the availability of private capital and your comments on its ability to invest at certain multiples, you partnered in the DJ. Are there other opportunities to partner with private capital that may be available to leverage your system as a whole?

Absolutely. The good news is we are seen as a very reliable operator with significant footprints already. I’d cite that the Northeast area offers a lot of consolidation opportunity and the ability to reduce capital investment in the area. We provide great investment opportunities for infrastructure funds to invest alongside us. Chad’s team is really engaged with a lot of those sources of funds right now and has a lot of irons in the fire.

Okay, good. Moving to the Gulf of Mexico. My sense is some potential growth comes at lower CapEx needs. Can you frame that a bit, what might be the nearest term opportunity to get operational leverage into the system, and where would be more meaningful investments to further that, maybe around Mexico deep water realizing that's still longer-dated?

We have a lot of tieback opportunities we’re working on that require low or no capital due to existing infrastructure already installed. We are actively working on a number of those opportunities and will build those into our future guidance as we speak, so we’re optimistic about the Gulf of Mexico. Our Discovery system has several opportunities, and we expect some from the deep water in Mexico around Perdido.

To mention a few, we already noted previously the Chevron-Ballymore prospect in the Eastern Gulf, the Shell well prospect in the West, and several Chevron prospects in the Central Gulf that we’re working on. The list is pretty long, with some prospects being more certain than others. Large finds like Ballymore and Well could provide very significant revenue and EBITDA growth with very little capital required.

Okay, makes sense. Just one last one. Thinking longer term with the liquids you will control out of Rockies Midstream, does that present opportunities for downstream investment? How are you thinking about securing access to the coast for those barrels long-term?

I’m going to dodge that question for now. We are working on several opportunities, and we’re excited about how we’re going to position ourselves for the future, but we’re in discussions right now, so it doesn’t make sense to lay it out at this point.

Fair enough. Thanks.

Thanks.

Yeah. Hey, guys, two questions. One, just on the Northeast G&P, kind of that CAGR you put out. How are you thinking about the cadence of that? Is it very front-end loaded in 2019 and tailing off? Or are you all looking at that more evenly spread out?

It will obviously come on in chunks. We’ve got an expansion underway now in Northeast Pennsylvania increasing our capacity there by 800 MMcf a day. That will come on in tranches in 2019 as we add compression and pipeline looping to nearly 4 Bcf a day on that system alone. We’re gearing up for that and talking with producers now about the next expansion behind that 800 MMcf a day.

Got it. Thank you, Michael. Much appreciated.

Good morning.

Hey, Craig.

Regarding the average $500 million a year multiyear figure for Northeast G&P to get to the levels discussed at the May 2017 Analyst Day, can we assume that capital spend necessary in 2020 and 2021 would be significantly lower to still shoulder that roughly 11 Bcf a day in 2021?

For the trajectory of growth we’re discussing right now, that is a fair assumption. One opportunity that could further reduce capital would be consolidating joint ventures in the Southwestern part of the play, such as with the Utica system, Blue Racer, and OVM. We have some significant consolidation opportunities out there that could help reduce future capital requirements.

Excellent. The 15% CAGR seems to imply over three years about 11 Bcf, but also in the third quarter your adjusted EBITDA was approaching $0.42 NM versus less than $0.39 for the first half of 2017. You're guiding that to grow even further. Given the combination of above-growth processing, increasing West gas volumes, and higher overall system utilization, is it reasonable to think that by 2021 we could be at $0.50 plus NM implying gross segment EBITDA of over $2 billion on 11 Bcf a day?

That's a lot of math you went through, Craig. But I would say as we continue to look at the marker from our Analyst Day, we feel confident moving in this direction at a good pace. That was set out aspirationally, but it was based on the Wood/Matt growth level. Now, we’re growing more focus on what’s driving our own results rather than just broader trends in the basin.

Got it. Just to simplify it, if you're approaching $0.42 NM in adjusted EBITDA, is it unreasonable to think you could hit $0.50 plus by 2021?

That is very reasonable to think that we could get there by 2020. Obviously, it will depend on the volume mix, but a lot of areas that had suffered from growth due to infrastructure limitations are now on an upward trend, which is a positive indicator for us.

Last question, when you say 10% into 2019 and 5% to 7% long-term, is that off the 2019 level or in aggregate over several years?

That is off of 2019 looking forward. Keep in mind that is based only on our existing contracted business. There's potential for improvement as we continue to grow organically in the business.

Understood. Thank you for the call. Congrats on the quarter.

Thank you.

Hi, Alan.

Good morning.

Thanks for all the guided detail this morning. Two questions for me if I could. First, in looking through the 10-Q you filed, it seems you've had roughly a $430 million working capital headwind over the last four quarters, which is significantly more than I could find in the last 10 years. I'm curious what’s driving that and if we might expect it to reverse in future quarters?

I’m not aware of any unique working capital drop. If I had to guess, we've had a significant amount of capital spend resulting in a build in payables at quarter-end for projects underway that we know we've invested in but haven't had outflows yet. We’ll look into it more but I suspect that it’s due to capital spending.

Okay. If your hunch is correct, we should anticipate a reversal in the future?

Yes.

Okay. The second question is about the preferred stock contribution to the Williams Foundation. I haven’t seen you guys do anything like that before, and I was wondering what the terms of that preferred stock are and your future plans for contributions to the foundation.

The preferred stock has a 7.25% coupon. We have no plans to add anything to that. That was part of planning and structure around the roll-up, similar to what ONEOK had done. We will annually make a contribution to our foundation. Whether that's through cash contributions or dividends, the outcome is the same for Williams.

Okay, so this is consistent with your historical treatment, just a streamlined approach?

Correct. It accomplished a structural need we had in the roll-up. In a practical sense, it was driven by that structure but worked into the foundation as part of being a good neighbor in our operating communities. The Williams Foundation is vital in that respect.

Alright, thanks a lot for your time today.

Good morning. Alan and Michael, just circling back briefly to the comments on margin expansion in the Northeast. You noted the overall uplift there at the EBITDA level, but regarding cost, it seems unit costs have held steady year-to-date. As you look at the volume ramp and dial in your expectations for 2019, how should we think about the progression of OpEx for that year?

We’ll have higher costs as we add compression and operators for the equipment, but I remind you that most of our compression added is electric due to regulatory constraints. That, however, will be reimbursed by our customers, so you won’t see it netted out on our operating cost line.

So, in terms of overall expectation, declining unit costs won’t directly reflect on line item specifics?

That’s right. We continue to see our EBITDA per Mcf moving in the right direction, with costs meeting that expectation as well.

Got it. Regarding the West, there’s been a slight downtick in volumes. Can you provide more detail on what’s happening at the basin level? And also, any thoughts on the impact to the Piceance?

Most of the Piceance is on federal land; Colorado Proposition 112 won't affect that. Many producers own the land they operate on, so expect no significant impact. As for the Western volume declines, the Haynesville growth had been the primary driver behind growth there and we've projected a level-off. We’re seeing new customer opportunities and we remain optimistic regarding that performance.

Got it. Appreciate your time today.

Thank you.

Hi, guys. Thanks for taking my question. On the DJ Basin, I understand your comments on wells permitted and DUCs. But let’s say hypothetically this proposition does pass. How much of your 5% to 7% EBITDA growth is attributable to DJ Basin growth?

For now, it doesn't represent a large portion of our overall 5% to 7% growth reflected in our projections. However, as we look ahead into 2020 and 2021, this could turn more substantial.

Super. Just a quick follow-up on your thought process on investments assuming this does not pass. There's still a view this will come up either legislatively or in a couple years. How does that impact long-term decisions?

I believe we'll see responsible development. Williams is effective at being responsible, and I think the industry will shape itself to adapt. These challenges won't just be limited to Colorado, and the producers and midstream providers must engage stakeholders effectively. I think we're positioned well for managing expectations favorably.

Thank you. I wanted to clarify that in your guidance there is zero uplift from the Transco rate case?

That's correct.

Perfect. Thank you.

Thank you.

Hi, everyone. I just have one question on the Northeast. The 15% CAGR, could you give us a general idea of the breakdown of that growth between Northeast PA and Southwestern PA/West Virginia? Just trying to get a sense of whether one is expected to have higher growth than the other.

On a percentage basis, the two highest areas would be Ohio River Supply Hub on a margin basis, followed by Susquehanna Supply Hub. The Bradford Supply Hub would be next. The Utica supply would come behind those. However, there honestly is minimal difference across those CAGRs, making the forecast very balanced.

That’s helpful. I wanted to ask about your equity method investments in the Northeast, which saw a jump quarter-over-quarter. Could you talk about which JV specifically drove that and how we should think about it going forward?

That's likely due to the Bradford JV. We had a notable increase in volumes from that JV, and Marcellus South also contributed to that increase.

Bradford had about a 9% increase in volumes quarter-over-quarter.

Got it. Perfect. Thank you.

Thank you.

Good morning. Just two quick ones for me. First, have you noticed interest from different classes of generalist investors since the buy-in of WPZ, or has nothing really changed that much?

Nothing has changed that much. I think our stock price would reflect some stronger interest if that were the case. We are focused on talking to new investors. We have spent some time in Europe and will continue engaging with other markets to attract new interest in our company. We think we have a compelling story to share regarding stability, strong yield and business growth.

That makes sense. Could you give some color on the mood of the Permian E&Ps in signing up for gas takeaway? Do most believe they’ll be able to flare if they need to, reducing pressure to sign up at all? Or, do you feel they probably will sign up, but perhaps with competitors other than Bluebonnet?

Chad, would you like to take that?

There have been two projects sanctioned thus far for 4 Bcf a day of takeaway capacity which alleviates some near-term pressure. Those projects have a variety of investors and risk-adjusted returns that wouldn’t be appealing to us, so we will remain disciplined and thoughtful. We're actively engaging with every producer and looking at every opportunity, but any investment from the Permian to our Gulf Coast assets will need to be a smart investment. Even if we don’t participate in building a pipeline from the Permian to our coast, we’re seeing interest in moving those volumes to the Transco system. Therefore, we will find ways to participate in moving Permian gas through our own infrastructure.

Sure. That makes sense. That's all for me, thank you.

Great. Thank you.

Great. Thank you. We appreciate the great questions and we are excited about the third quarter outcome. Importantly, this sets up a strong platform for growth going forward. We have stable cash flows and will strive to make our numbers. We look forward to reporting additional good news next quarter. Thank you.