Williams Cos Inc (WMB) — Q1 2019 Earnings Call Transcript

Thanks, David. Good morning and thank you for your interest in The Williams Companies. Yesterday afternoon we released our earnings press release and the presentation, that our President and CEO, Alan Armstrong will speak to momentarily. Joining us today is our Chief Operating Officer, Micheal Dunn; our CFO, John Chandler; and our Senior Vice President of Corporate Strategic Development, Chad Zamarin. I've also mentioned that we've refined our quarterly earnings materials and our format for this call. We've adopted a clear earnings press release format and we've integrated the previous stand-alone analyst package into the earnings release documents. So we now basically have one document rather than two. 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 non-GAAP measures that we've reconciled to generally accepted accounting principles. These reconciliation schedules appear at the back of today's presentation materials. And so with that, I'll turn it over to Alan Armstrong.

Great. Thanks, John, and good morning and thank you for joining us this morning, as we discuss our first quarter financial performance and the key investor focus areas today. As John said, we took a fresh look at the format and we're going to stay pretty brief and focused in our prepared remarks, to allow time for Q&A. So let's move right into the presentation and take a look at our first quarter 2019 results. On Slide 2, we provided a clear view of our year-over-year financial performance and the results you see reflect continued steady and predictable operational performance and strong project execution from our E&C team. The results reflect very little direct commodity exposure; in fact, our first quarter 2019 gross margin reflects 98% fee-based versus only 2% in direct commodity margins. These contracted fee-based revenues are not dependent on basis differentials or commodity buy-sell transactions, allowing for continued predictability and durability in our cash flow streams. So taking from the top here, cash flow from operations increased 12%, demonstrating significant free cash flow in the quarter when compared with the 46% reduction in the capital expenditures you see at the bottom of the slide. There's much more to say about the adjusted EBITDA performance on the next couple of slides, where you can see here that it increased 7% year-over-year without adjusting for asset sales. In addition, you see a nice improvement of 16% for our adjusted EPS, and on DCF we were up about 8% and we've also introduced DCF per share on this summary, which grew about 7% versus last year, and lastly our strong 1.7 times dividend coverage also increased versus the prior year. So really nice improvement on our various earnings and cash flow metrics despite the impact of significant asset sales. Now let's turn to Slide 3 and review where we finished the quarter on our leverage metrics. The leverage story of the quarter end requires some unpacking since we have significant asset sale proceeds coming in post the quarter's end. To start with, if you consider the debt-to-adjusted EBITDA directly from the March 31, 2019 financial statement, you get a value of 4.92 times. However, that metric includes about $727 million where we purchased the remaining 38% interest in UEOM funded partially with our revolver right at the end of Q1. But we'll be refunded with proceeds reserved at the closing of the UEOM, OVM, JV that we completed with CPPIB, while the latter's there. If you adjust out that $727 million in cash we plan to receive at the closing of the JV, the leverage metric falls to 4.77 times. Furthermore, if you account for the approximately $600 million of additional proceeds we will receive from CPPIB at the closing of the JV along with the $485 million we have now received from Crestwood, as part of the Jackalope Gas Gathering transaction, the leverage metric falls to just over 4.5. I'll discuss the strategic transactions and leverage goals in more detail later, but now let's move on to Slide 4 to discuss the main business drivers for our year-over-year adjusted EBITDA growth. On a year-over-year basis adjusted EBITDA increased just over 7% or 11% if you adjust for asset sales. On this slide, you can see a $37 million comparability adjustment driven by asset sales including the adjusted EBITDA from the sale of Four Corners assets, the Gulf Coast purity pipeline and the Brazos JV accounting changes. Now moving over to look at the financial performance of the continuing business, Atlantic-Gulf led the increase with an over 20% increase in adjusted EBITDA, driven by top-line revenue growth from new expansion projects including Atlantic Sunrise and Gulf Connector. It's really impressive growth from Atlantic-Gulf driven primarily by continued projects that have been going into service on a regular basis on Transco. Next, looking at the Northeast G&P area, we also see just over a 20% increase in year-over-year adjusted EBITDA. This was driven by 15% higher gathering volumes and higher gathering fees associated with expansion projects. Volume increases were led by the Susquehanna Supply Hub area which grew about 25%, but we also saw double-digit growth rates in the Marcellus South and Utica and a high single-digit growth in the Bradford and OVM areas, so overall a very nice start to the year for the Northeast GMP. Finally, in the West, we are showing about a 7% decrease in year-over-year adjusted EBITDA after adjusting for our share of the asset sales described earlier. That decline is primarily driven by lower NGL margins due to a temporary surge in natural gas prices at Opal, and the effects of severe winter weather affecting one of our key customers' production in the Wamsutter, Wyoming field. Importantly, our operations team in the area was able to keep our facilities ready and available but upstream production freezing off was the culprit in the area. Next, let's look at the sequential adjusted EBITDA growth where we saw about a 2% increase since last quarter, a modest increase in EBITDA for the first quarter of 2019 versus the fourth quarter of 2018, as you can see here on Slide 5. Of course, it's important to note that there were two fewer days in the quarter which by itself caused about a $26 million or 2% impact. The Atlantic-Gulf was up about $30 million over the fourth quarter, driven by lower O&M costs and Transco revenues were higher related to Gulf Connector, but lower due to Gulfstar One volumes caused by well maintenance. The Northeast G&P was pretty flat to the fourth quarter, where increased revenue and lower O&M expenses were offset by lower wet Utica gathering and JV EBITDA from Aux Sable for our interest -- Aux Sable and Blue Racer midstream recall that Aux Sable is an on-off interest in a processing complex in Illinois. As we discussed in the past, the Northeast EBITDA growth in 2019 is more weighted toward the second half of 2019, and we'll be covering the outlook for the Northeast in more detail in a moment. Finally, the West is pretty stable compared to Q4 of 2018. Revenues and O&M were relatively flat sequentially and per unit NGL margins were quite a bit weaker. However, on a sequential basis, those lower per unit NGL margins were more than offset by the favorable change we had in our NGL line fill evaluation margins. As you may recall, our fourth quarter 2018 marketing margins were unfavorably impacted by the same losses in marketing inventory. Prices move up and down, and the line fill evaluation swings accordingly. Lastly, in the West, we also saw some nice sequential double-digit growth in the Haynesville. So overall, volumes were flat due to the severe weather in the first quarter of 2019, again from the Wamsutter volumes which were down in Q1 as mentioned earlier. So generally in Haynesville, we had some nice growth, but it was pretty well offset by the long set of volume declines in increase off there. In summary, Q1 adjusted EBITDA was within 1% of our business plan overall. As we've said before, we see the overall 2019 growth to be weighted more toward the second half of the year, due primarily to the shape of the Northeast EBITDA growth. So let's move to Slide 6, where we'll spend the remainder of the prepared remarks focused on our views around some of the topics we most frequently discuss with our investors. The first item we'll be discussing is our financial status update. A lot has changed since we originally issued our 2019 guidance about a year ago. From a macro perspective, we've seen our producer customers pressured to pull back on capital investment, and we've seen a significant downward shift in NGL margins. We've also had five important portfolio optimization transactions including the Four Corners of DJ Basin transaction, the sale of our Gulf Coast purity business, our Northeast JV that we mentioned, and most recently, the sale of our Niobrara business. Therefore, lots of moving parts since we laid out our guidance this time last year. But I'm pleased to confirm that despite these unforecasted changes, we are maintaining our guidance ranges for adjusted EBITDA DCF and dividend coverage ratio. We are actually raising our guidance for adjusted EPS to $0.95 at the midpoint due primarily to some lower depreciation expenses caused by last year's Bernard impairment and lower expected interest expense, thanks to deleveraging efforts. If you look in the Appendix at Slide 13, you can also see that we've added a DCF per share metric and provided a bridge between DCF per share and EPS. We've had lots of discussions with investors about the very significant non-cash charges that impact our EPS, so we've given more visibility in that development. On the growth capital expenditures front, we've seen quite a bit of changes since last year associated with deleveraging efforts and new projects like the Bluestem Pipeline. As we'll discuss further in a moment, we are targeting a lowering of our CapEx in the Northeast G&P business, to respond to producer activity in the region. Our teams are doing a really nice job of ensuring that we bring that capital on just in time and don't get anything out in front of the drilling operation. So, really nice work by our teams here, that are constantly operating in a very agile manner. When you net all of these changes, we're revising our consolidated growth CapEx guidance to a new midpoint of $2.4 billion, down from the $2.8 billion midpoint that was provided with our fourth quarter earnings release. When you factor in the new Northeast JV, our total contributions from JV partners this year increase another $120 million in addition to that $400 million reduction in the stated growth capital. Considering the proceeds we received from the Northeast JV and Niobrara transactions along with our excess cash after dividends, we expect to fund our 2019 capital expenditure need with operating cash flows and proceeds from these transactions. The effects of our portfolio optimization transactions along with our lower capital expenditure forecast have had a favorable effect on our 2019 year-end book debt-to-adjusted EBITDA, which we now expect to be under 4.6 times. Looking beyond 2019, we are still expecting 5% to 7% annual adjusted EBITDA growth over the long term. So let's move on to the next topic which is an update on the Northeast growth. As you'll probably recall at our third quarter earnings call, we introduced a forecasted 15% CAGR for the Northeast area gathering volume growth for 2018 through 2021. Since then, we continue to work with our producer customers during two more forecasting cycles. Since last fall, delays in outages on Mariner East and delays on major gas takeaway pipelines like MVP have dampened the realized price expectations for producers in the area on a forecasted basis. Despite this price decline, I'm pleased to say that we are still expecting to see a 15% growth rate again this year on gathered volumes and a slightly higher EBITDA growth rate for the Northeast in 2019. Most of this is supported by great performers like Cabot and Southwestern. But increasingly we will see the impacts of additional investments by Encino on their new Utica acreage. With the recent weakening of forecasted commodity prices, fewer producer customers have focused on tuning their drilling CapEx, directly to their free cash flows, and therefore producer forecasts at this point where 2020 and 2021 are very sensitive to forecasted pricing. Very importantly, a lot of the planning is done around forecasted pricing; as prices change we see producers shifting that accordingly. Right now, I would say with the pressure we've seen in local NGL prices in the area, that has pulled some of the capital out of some of the wet Marcellus areas, and that is embedded in the forecast. We think it is wise and good for the long-term sustainability for our producer customers to take this agile and measured approach, and we applaud the capital discipline. Over the long term, we believe that demand growth ultimately will drive producer volumes. Demand from converted power generation, LNG exports, and new industrial loads is continuing to grow after several years of heavy capital investment and construction. Now we are seeing a second wave as the Permian gas supplies have further convinced the world that the U.S. has sustainable low gas supplies for decades to come. Therefore, we do not believe that the current downturn in pricing is sustainable, given the continuous growth in natural gas demand, coupled with the discipline we have seen from the producer community. While Permian supplies are a needed resource to increase demand, we still have two-thirds of our gas supplies here in the U.S. being generated by gas, only directed drilling that will have to have a price signal, and has become evident that we simply can't get the infrastructure built fast enough out of the Permian to keep up with the demand it continues to grow. While those fundamentals continue to support our steady and sustainable long-term growth, we do want to be transparent about the producers’ forecasts as they relate to our near-term gathering volume and growth rate. Using the current detailed forecast from our producers, our gathering volumes CAGR is expected to be a very impressive 10% to 15% growth through 2021. While our EBITDA CAGR would still come out at or above 15% through the same period. On this front, I am pleased to say that our capital programs are closely aligned with our producers, allowing us to reduce growth CapEx to more efficiently place capital against the same amount of producible reserves. We are encouraged to see the level of EBITDA growth in our Northeast G&P business, which can continue to generate even with reduced capital being applied, and this combined with synergies from our new JV will allow us to place capital more efficiently than ever in this important basin. Next up, let's get an update on our deleveraging efforts. With that excellent execution this year on our portfolio optimization efforts, the Northeast JV transaction with CPPIB accomplished multiple benefits for the Company. Consolidating the UEOM and the OVM systems while bringing up immediate cash for deleveraging and aligning us with long-term strategic partners who also own and control one of the most important customers in the area, Encino. Encino has attracted some very experienced and capable personnel, and we are excited to be forming another key mutually beneficial relationship in the region, much like we have with Cabot and Southwestern today. The Niobrara transaction allowed us to accelerate deleveraging by exiting an area that wasn't strategically connected to the rest of our business network, and this transaction was priced at the same strong mid-teens multiples we've realized in other portfolio optimization transactions. So no changes to our long-term leverage target of 4.2, which we target to hit by the end of 2021 while maintaining the 5% to 7% annual growth targets over this timeframe. So let's move on to Slide 7 and start with an update on the Transco rate case. As we previously discussed, we filed for an annual rate increase in our August 2018 filing. Those new higher rates went into effect on March 1. Currently, we’re receiving the higher cash payments from our customers subject to refund, but you won't see that reflected in our results as we're reserving the increase pending ongoing settlement negotiations. On the settlement progress front, we've had two conferences recently and we'll have another in May. The negotiations are confidential as long as we remain in the settlement process, so I can't share where we stand with the counter parties at this time. I can tell you that the settlement negotiations are likely to continue for many months and could extend into the next year. We are hopeful that the settlement can ultimately be reached without the need for litigation and that the settlement would include the $1.2 billion emissions reduction investment opportunities. We continue to not have any of that upside from the rate case reflected in our financial guidance. Let's also touch on the status of Transco's major growth projects here. There's a lot of news out there these days and questions regarding the effects of the recent Presidential Executive Order on our projects. Obviously Williams supports efforts to foster coordination, predictability, and transparency in the federal environmental reviews and the permitting process for energy infrastructure projects. Along those lines, we were actually very impressed with the level of detail that appeared in the executive order on complex issues like the EPA's water quality certification requirements and we appreciate the administration's efforts in strong support of a sustainable approach to ensuring consistent application of EPA's regulations. However, we know that any major shifts in policy coming from the executive order will likely be challenged by opponents of infrastructure and fossil fuels, no matter how clean. We deal with these permitting challenges on a daily basis, and our project development teams consistently do a great job of navigating those. Beyond presidential orders, we continue to advance our key New York and New Jersey projects like the Northeast Supply Enhancement project, the Rivervale South expansion, and our Gateway expansion by demonstrating their critical importance to the markets they serve and the quality of our execution track record, as was most recently demonstrated by our teams on Atlantic Sunrise. Transco's large-scale existing right-of-way and vast interconnection network are really the best way to bring clean, safe, affordable, and reliable natural gas to these Northeast population centers, allowing these regions to continue to lower greenhouse gas emissions. To that end, we continue to press on with the 20-plus Transco projects we currently have in development, including the most recently announced Regional Energy Access project. The binding open season for our Regional Energy Access was extended from April 8 to May 8 to give shippers additional time to get the approvals they needed not just for indication of interest but for binding commitments. We’ve been impressed with the interest this project has garnered. We are targeting a final investment decision in the third quarter of this year with pre-filing to follow. Next, I’ll touch on our growth in the DJ Basin area. Since February, there have been ongoing developments in Colorado as the new executive and legislative leadership of the state have taken action to address oil and gas development laws. Ultimately, the new legislation seems to present a much more balanced approach than what we saw last fall, with the sale proposition going well, with the vast majority of oil and gas activity occurring in the industry-friendly wealth county area. We welcome the shift and authority to local counties and municipalities, and we will continue to monitor as regulations are developed. In fact, our teams are working hard right now to keep up with the growth, supported by a long backlog of currently permitted wells. During early April, we started up our new $200 million cubic feet-per-day Fort Lupton III cryo and train, which is running very reliably, and kudos to the team for getting started up safely. Construction is progressing very nicely on our team’s Keenesburg I cryo, which should be online in the third quarter of this year. In February, we signed another new pact for gas along with NGL marketing rights right in that same area where we're continuing to develop infrastructure. So we are very pleased right now with the strong demand for reliable gathering and processing services in the area, and we look forward to continued growth and support for our NGL marketing businesses including the Bluestem pipeline projects and associated upgrades at Convoy. Last but not least, we have seen a steady increase in that, pivoting to the deepwater Gulf of Mexico for substantial new discoveries that are being made in close proximity to our assets. This is an area where our existing assets and acreage dedications give us tremendous competitive advantages, and we are thrilled to see the dramatic rebound of activity that is focused on keeping costs and cycle times low by utilizing existing infrastructure like ours. This year, we'll see EBITDA contributions from our Northwest projects including those from the purchase of the Northwest Pipeline and additions to our Mobile Bay processing complex that we completed last year. Our Northwest Pipeline purchase will be paid for once first oil begins later this year, and we have line of sight to existing new potential business with likely FIDs in 2020 on several major projects that would lead to large incremental free cash flows on our existing asset base in 2022 and beyond. As I promised on the introductory side, we will try to keep things brief today. We are pleased to update you on the solid first quarter performance and great transactional progress that is accelerating our natural rate of deleveraging. With that, let's continue the discussion in our Q&A session.

I wanted to start off with the Northeast G&P and I was wondering if maybe you can provide a little bit more detail with the volume growth that you're talking about. Maybe some thoughts on the cadence there, how you see that progressing over the next several years based on producer conversations, and also kind of CapEx specific to this area? Has that lightened up at all?

Yes. In terms of cadence, I would just say right now we've got a lot of activity, a lot of wells being turned in the line right now as we speak actually here in the last month. So a lot is happening out there right now, it's all over the place both in the Northeast and the Southwest. In the Utica area, the Encino team there has just now taken over operations of that area and transitioned from Chesapeake. We are really working closely with them to have kind of the same kind of integrated approach to development and growth as we have with both Cabot and Southwestern, so really excited about the team they've pulled together there at Encino and our ability to work with them. In terms of kind of the cadence, I would just say certainly, Cabot intends to lead the way with development with 20% kind of growth. So I would think the Northeast PA continues, they have continued to invest with or support our expansions of further expansions of our gathering systems out there. Of course, we're very interested in additional takeaway capacity out of the area given the big reserves and the low-cost reserves they have in the area. I would say there really hasn't been anything other than just continued steady performance by Cabot, and we're starting to see that kind of spread into some of the other areas as well, like in the Bradford area. So I think the Northeast is very predictable and steady. The areas that have more I would say volatility in terms of ups and downs and perhaps things are little more reactive -- the prices, is in the west gas areas like I mentioned earlier, both the Marcellus wet and the Utica wet. A lot of that, I would tell you is driven by pretty sharp price; realized price decline on NGLs which were associated with the Mariner East up and down, during the course of now hoping for expanded capacity out of their own Mariner East 2. I would say that the pricing forecast on NGL has been difficult to predict. The gas takeaway situation, particularly with the MVP has been pushed back a little bit as well. I think those things will resolve themselves as we get into 2020, but we are seeing producers be very responsive and I would say very strict about living within their cash flows and their forecasted cash flows. Of course, that requires them to forecast prices. But I think that's what we can look to in terms of signals there. Our drilled outflow continues to be pretty robust for both the Southwest PA and Utica area, with a lot of new capital. But we are finding ways to really trim that back and have capital come on just in time as production comes on, and that’s what you see reflected in some of our capital pullback and redemption in capital that you see here in our guidance.

That's helpful. Thanks for that. Turning to UEO-OMV, the combination there, just wondering if you might be able to provide a little bit more detail in terms of some of the synergies you see bringing those two assets together as far as capital efficiency improvements.

Yes. Great question. It's reeling on two fronts. First of all, the very simple front there, is on the liquids front, so we have the Moundsville fractionator sitting there, that has been running right up against its maximum capacity and we had some investments that were going to be required there to continue to operate that facility and expand it. Now, we're going to enjoy being able to put those liquids through our new pipeline that we're building over to the Harrison fractionator. We'll be taking those liquids over to the excess capacity, big excess capacity that exists at the Kensington fractionator. So they were sitting there leveraging a lot of the latent capacity on the fractionation side, and better markets there at the Kensington area. So effectively, it allows us to shift our focus of growth for fractionation and reduce any investment required at Moundsville, quickly take that capital out of our capital plan, so that’s the simple side. On the more complex side, we are looking at ways to take advantage of the excess processing capacity that UEOM enjoys. We’re starting to run up on the capacity constraints at OVM, and if growth continues there we will be looking for ways to move volumes over to UEO as well. Those are kind of some of the obvious issues. We have management consolidation and overhead consolidation, that's beneficial to us. But a lot of it really just relates to being able to take capital out of our plan that would have otherwise been in there.

That's really helpful. Thanks. Last one if I could, it seems like NESE could really lower CO2 emissions by displacing dirtier fuels. Just wondering how that messaging is resonating in the communities that you're looking to operate in there? When do you see kind of the path forward at this point as far as permits being -- when construction could start there?

We absolutely think that NESE is a key piece of the puzzle in New York City and the New Jersey metropolitan area to reduce emissions, especially CO2 emissions. It's very dramatic in regard to the emissions profile of the fuel oil currently being used, and converted to natural gas up there. We are going to be a key part of that continuing opportunity to convert. If NESE gets approved, and we think it will, and gets built. The permitting process is currently in the late stages here. We expect to receive a FERC certificate for that project any day now. The 401 Certification deadline in New York was mid-May. The 401 Certification deadline in New Jersey is mid-June. So, we would expect several of those permits to come to the forefront here in rapid succession.

Just to follow up on the Northeast questions a little bit. Your first and foremost just the consolidation of UEO into Williams or the UEO transaction rather. Is that sort of changed your weighted average growth rate kind of beyond 2019? And when you talked about being able to take down CapEx, what you've done materially for this year, does this CapEx efficiency benefit roll into 2020 and beyond?

First of all, on the gathering volume fees, it really doesn't change that, because remember we're already operating the gathering systems that feed into UEO, so those gathering volumes would have already been included in there. So their drilling not any change on that UEO, is primarily just the fractionation of processing facilities downstream to that. On the question about capital savings going forward, I would say a big chunk of the capital savings and the synergies are actually now forward-looking as we take advantage of balancing between the two processing complexes and the liquids. So a lot of the gathering capital really won't change that much. If you think about it, it's really on the processing and fractionation capital that will be able to shift volumes into areas that would not have necessitated expansions.

Great color. Just another follow-up kind of a bigger picture question. You sort of talked about in your prepared remarks about a longer-term growth rate of 5% to 7% for EBITDA. Can you talk about what kind of capital program would be needed to support that type of long-term growth rate? And could we assume it would be funded at least 50% from internally generated cash flows?

Yes. I'll let John Chandler take that in terms of where we would go with that. As we said, the $2.5 billion to $3 billion, assuming a little more moderated returns than we've been enjoying generates that 5% to 7% growth rate. Obviously, as we can high-grade our investments that improves and bring in synergies like we're doing with these JVs. But generally that $2.5 billion to $3 billion is what we think it takes to grow at that 5% to 7%. I will let John talk about the funding.

I think that's fair. As we look forward in our projections today, using this $2.5 billion as the number, a tight expansion capital. As we look to our forecast, we're able to fund that completely and entirely through excess cash flow. Obviously, some new leverage in the future, but with the growth of our EBITDA, we're able to maintain and continue to lower our leverage ratio going forward, and fund that capital expenditure that aligns with that kind of EBITDA growth.

So with your -- effectively once you hit your leverage target, will there then be room to consider share repurchase business as well?

We can talk about that once we get there. There is still work to do obviously between 4 -- under 4.6 to 4.2, there is still quite a bit of work for us to do. So I think we've got time to talk about that, but certainly when we get to the point where our leverage targets are where they need to be, we will be generating a significant amount of excess cash flow.

Yes, so I would just say on that front, we'll see what the markets look like when we get to that point. It's kind of hard to answer that, because we're speculating on what the returns would be on that investment versus our other investment. But I can't tell you we're constantly allocating out capital return projects that a lot of the industry would accept. There will be a balance there between increased capital investment opportunity, and what we can do with that capital. We are constantly allocating towards these projects today as we continue to press on deleveraging the business.

Okay. And one last question if I may. Your excitement level about the Gulf of Mexico seems to be increasing. You sort of touched on the opportunities that you see there and how we should be thinking about it on a go-forward basis?

Yes. I would just say the opportunities are increasing to the point that it’s starting to get hard to keep track honestly -- but some very certain opportunities exist around the Gulf, especially our operations around the Perdido area. The well prospect out there is going to be a big mover for us. Shell just announced a little bit earlier this month or rather in April the Blacktip discovery which is also another very large discovery in that Perdido belt area. To the south of that, of course, the Mexico Perdido is even a much larger kind of magnitude opportunity, that we're extremely well-positioned for. On the Western Gulf, it’s about maximizing our return on the investments. There is plenty of production to fill up our existing capacity and then some more. Really important opportunities for us out there, and we're just extremely well-positioned both contractually and with the infrastructure that we have in place out here today. If you move over to Gulf East, of course, we are really excited about the Ballymore prospect that will likely get produced across the Blind Faith -- Chevron Blind Faith platform. That's also a very large find there. Again, just big incremental free cash flows coming our way with little to no capital on our part, so we're excited about that. The Northwest prospect while we kind of thought that was almost singular as an investment, originally we liked the returns just singularly across that one field. We’ve seen a lot of new development out there around the North, not just by Shell but also by Chevron now in that area. A lot of new development is happening there as well. I’m not even getting into the multitude of the smaller projects that are on our radar. A lot of the reason that I think we're so fortunate is that in the past, what we saw was producers really looking to add big reserves, and when oil was $80 to $90, as they were enjoying prior to '14, there wasn't so much focus on the use of existing infrastructure to keep costs down. Now, with the lower prices, we're seeing a huge focus on utilizing existing infrastructure, which means we don't have to build a bunch of new capital. It's just development in and around our existing assets, and that is really good for us and really good for the industry as a whole. That, I would say, is the big change from the last time we saw the deepwater take off.

Yes, I'd like to add to that -- on the opportunities, that was a great negotiation for us to have with Shell there where we acquired the pipeline that they built, it was pretty negotiated with the return. We're obligated obviously to move their gas to shore through our Mobile Bay facilities, where we have a percent of liquids contract with them to process that gas. The strategic value there, in addition to us, is the pipeline won't be full from day one. We can go out and acquire other business to bring through that with subsea tie-backs into that Northwest pipeline, that we can purchase upon first gas movement there. So it’s a great opportunity for us to take advantage of that facility that has already been built, eliminating construction risks and timing risks because we don't pay for it until the gas flows.

Good morning, everyone. You guys have talked about wanting to consolidate the Northeast for some time. Obviously, the UEOM tend to actually test you in that direction. How should we think about the potential for Blue Racer to be included under that umbrella?

Great question, Christine, as always. There is a lot of value in that combination, we're working through some various transactions to try to extract some of that other than through direct control of the asset. But certainly a lot of opportunity there. But I would just say we haven't been able to get there from a price standpoint; we haven’t been able to get to what we thought would make sense for us on that. So, I would say lots of opportunity, but we remain patient and will continue to do so.

Okay. You guys are tracking to get to your targeted leverage faster than planned. Should we think that there are any other non-core aspects that you're contemplating selling? Or is this sort of it?

Well, I would just say we're always looking; we continue to see this big spread between what our stock is trading for versus what these assets are selling for. So if we can do those kinds of transactions in a way that don't dilute our future and stand in a way of accomplishing our strategies, then we'll continue to look through those. But we don't have anything specific on the drawing boards. As we said forth, looking toward our strategy and how things link with our asset base is not dictated by rules that says we have to have the downstream business. But when placing capital and new capital, it competes in this capital allocation process that we're constantly running. If it doesn’t enjoy downstream benefits, the incremental returns just don’t stand out. The Niobrara is a perfect example of that. The returns on a standalone G&P basis just didn't stack up well within our capital allocation program. Partners and customers became frustrated with our lack of interest in investing at those return levels, and that wasn't for any reason other than the distant stack within our capital allocation process.

I would also say, though, there is possibly cheap money looking for opportunities out in the marketplace and very similar to our Four Corners asset. We get approached by the market all the time on assets. Again, to Alan's point, we don’t have anything specific in the crosshairs right now, but we are constantly being approached.

I just had a quick question on the Transco rate case and some of the associated details around that. It seems like your timeline there has been extended, around settlement discussions. Can you just talk a little about the decisions to kind of keep going with some discussions and having an extended timeline here fairly considerably? I assume you're pretty confident in terms of your position there, so why not move to maybe litigate a little bit earlier than the end of 2020? Related to that, the emissions reductions expanded at Transco. Is that going to be part of the rate case or separated out, and is that something you would spend before the rate case was concluded?

I wouldn't say it's necessarily extended out per se, it’s just a process we have to go through in front of an administrative law judge regarding trying to reach a settlement. We think it's prudent to continue that process until we reach an impasse with our customers, but we certainly are not at that point yet. We are rapidly working with them to try to come to a settlement that both sides appreciate. It doesn't mean we won't be willing to litigate, we would consider litigation if we hit an impasse, and the administrative law judge will assist us in getting there fairly quickly. We are hopeful we can reach a settlement without needing litigation, and the settlement would include the $1.2 billion emissions reduction investment opportunities. We continue not to have any of that upside from the rate case reflected in our financial guidance. As for the emissions reduction, we’ve planned for that to be a separate tracker as we spend the capital; we would basically change the rate upwards to accommodate the compression that's been replaced there. It allows us to do that as if we were going through a rate case, without having to go through a formal rate case.

If I can just get more of an update on Bluestem and how discussions are going on that? It looks like recent oil prices have been motivating customers a little bit more. To what extent are you looking at partners there? Where could it stack up sort of on the returns profile or within your capital backlog?

I would just say we continue to work on projects in the Permian to Transco markets. We've seen recent dislocation in basis from the basin obviously to the coast. If you look at the forward curves, I think the market has been a little slow to recognize that might be long-term sustainable. So we are going to be really, I think, cautious in ensuring that any project that we proceed with are those with solid fundamentals and economics. If we were to move forward, it would be with partners. We are not looking to make an investment of that scale out of the basin on our own. Ultimately, what is important to us is to continue to build Transco's market connectivity both on the supply and demand side. We believe those volumes want to get to the best market, and Transco offers those very best markets, so again, we continue to explore participating in projects from the Permian to the Gulf coast.

Good morning. Actually, just a follow-up on the Bluebonnet discussions there. Have you seen any shift in producer willingness to flare given kind of the extreme focus on ESG for the upstream community over the last couple of months?

Yes, I think we continue to see quite a bit of flare, but I do think the producers are interested in getting gas to market. I think they're looking forward to release coming later in the year when the first long-haul project comes online. We've seen significant volumes shut-in in the alpine high area. I think we get a lot of questions around the large basis and why we haven't seen a stronger move toward the additional project. What we're seeing is, it takes a lot of time and effort to create infrastructure that can move all the way from West Texas to the market. We think another project needs to be built, but again if you look at the curve, the forward curves from basis from Waha to Henry Hub, right now those prices don't support investment in a long-haul pipeline. Until we see producers and end market users willing to step up for longer terms and better economics, I think we will continue to see challenges in the basin.

Got it. And just circling back to Q1 results here. The downtick in the Atlantic-Gulf operating expense, is that a function of timing on the maintenance spend or is there something more structural or nature to point to?

Yes, this is Michael. It’s not really a structural issue, it's just a timing issue of activity. We had some one-off issues last year that specifically in our unregulated business with turbine overhauls and things of that nature that contributed to that higher expense in the comparable quarter in 2018. So it's not really a structural issue.

Got it. So 2018 was probably an elevated level and this maybe is a better look at the go-forward rate?

I'm not going to predict future rates, other than to say that it is lumpy because of timing and specific terminal overhauls. They're pretty expensive, a couple of million dollars for terminal overhauls, and they have to be done at certain intervals of run time hours. We have to accomplish those and we also had some emerging problems to take care of. I would also say that in 2018 we also did a lot of work on our reciprocating compression on the Transco system that needed to be addressed as well.

A quick final clarification here. For the $400 million reduction of the capital program, I think you all noted previously that around $90 million was associated with Jackalope. Is the balance of the entirety there solely attributable to the Northeast? As we think about the Northeast, Alan I think you mentioned a just-in-time element for some of the reductions. Does that imply that any of this has shifted to 2020? Or should we think about it more in terms of the processing discussion you outlined?

First of all, it’s a combination on the last part of your question. It is a combination of stuff getting pushed out, as well as the ability to not have to continue to expand at Oak Grove and Moundsville. Yes, it’s getting pushed into '20 but you’ll see some of the benefit of synergy show up in '20 to offset that. The $90 million for Jackalope out of the $400 million overall is part of that. It includes some capital from getting on with the fractionation at Bellevue, as well as Bluestem, moving in there. Some capital is coming out of the Northeast and some lower capital for the year as these projects, we always have a lot of contingencies built into these projects, push out, and get closer. We advanced one of our Transco projects in 2020. Overall, we’re actually seeing really good performance on that front. For the most part, it is coming out of the Northeast, but not all.

On the executive order, you guys highlighted what's your expectation from the DOE. Is it worse to submit a report just on timing to get more clarity around that? Any input you all are having on that process?

Well, obviously on the Presidential Executive Order, first of all, we were really impressed with the work that was done by various staff attorneys around the EPA. I think everybody recognizes that some of the so-called guidelines, and I’ll use quotes around that term, had been put in place during the Obama administration, which have been treated almost like rules by the state, and in fact, there had really never been a regulatory process to establish that. The EPA administration has been trying to bring clarity to that. We think it's exactly what we've been asking for; we haven't been asking for easier regulations, we've been asking for clear and consistent regulations. That's exactly what we thought the order tried to address without overreaching toward any one particular project. It’s been a big step in the right direction to bring clarity and consistency in regards to how the states and the federal government deal with Clean Water Act regulations within the EPA. We're impressed with the sophistication of that work.

It makes sense. Just one more, you mentioned on Bellevue a couple of times. Maybe ignoring timing on end service, they've built a lot of that project. Assuming they get to Station 165, you talked about synergy; has that moved into commercializing anything at this point? If they have to wait on firmer in-service, just any color on the benefits there?

Sorry, just to clarify you were talking about Moundsville pipeline is that correct?

Yes, sorry about that. Moundsville pipeline.

Okay. Yes, thank you. This is Michael. Just seeing what the Moundsville pipeline backers have said about their project; obviously they feel certain in regard to completing their project. We're watching that very closely along with them. Ultimately, we'll get to Station 165 area and they're very likely should we take way opportunities for us, from that point on the Transco system, once that project gets closer to some certainty there. We're certainly looking at that and willing to take on any customer-related projects, that would like to move that gas away from the Station 165. We think there are opportunities to do that.

Hey, good morning. It looks like the latest growth into Transco from the Northeast Marcellus around 4.5 Bcf/d including Atlantic Sunrise. Is that effectively the max capacity for Transco there? Is there any way you could take more gas than you paid for? Just compression anything like that?

Just to remind everybody, Transco's capacity is fully sold, so it's consistently sold out of the [Technical Difficulty]. We're talking about interuption; how much we can flow during the period which is dependent on local loads where the gas needs to be delivered to. A lot of variables go into play. Generally, we are constantly maximizing capacity out of that basin right now due to margin support. But what I would say is every day we’re optimizing as much as we can move from that area.

Okay. That's helpful.

Current they are staying full just like Atlantic Sunrise has been virtually full almost since day one. It bodes well for future opportunities to move additional expansion volumes out of there. There are new projects like Regional Energy Access and Leidy South that we’re working on for National Fuel Gas and for Cabot. There are easy expansions out of that area, along with some improvement on compression and little bit of looping to do to add capacity.

That’s really helpful. Thank you. Do you still have any spare capacity in gathering in the Haynesville, I mean perhaps in the Eagle Ford or is your system pretty much maxed out there?

I’ll say in the Haynesville we bump up against the top end quite often as well pads come on. We get maximum capacity all throughout last year while continuing to find new volumes coming in there that try to max capacity. So, we're pretty maxed out in Haynesville from time to time, and that is highly dependent upon the [indiscernible] on those wells. In the Eagle Ford we continue to have new well connect opportunities. We're continuously expanding our systems there as needed for the producer customers out there, though most of that requires additional compression.

I'll be quick. I know there have been a bunch on both MVP and ACP. Hypothetically, if ACP, and let's say even if MVP didn't go through means got stuck in the court system, bogged down for a lot longer or cost creep inflated to a point that made it untenable. How do you think about the solutions that Williams could offer into Virginia North and maybe in the South Carolina? And the ability and timeline to realize some of those solutions?

Michael, obviously it's a topic that's been getting a lot of discussion. We have a lot to offer in terms of distributing the product with gas to market whether it’s healthy, what would be the ACP, Eastern system or moving supplies to them. We can help them with market distribution as we do get across the trial with those supplies. We have a tremendous amount to offer with our existing lighter weight. MDP is more just kind of a downstream issue because obviously they're getting across the trial with those supplies. We have the ability to help distribute that gas into the market.

Great. Thanks. Just one follow up for me, just if you take the Q1 run rate per CapEx for a bit below the full year guide, so is it more balanced throughout the rest of the year here? Or is it back end driven? Maybe just to hop on the cadence of the CapEx if you could?

Yes. This is Michael. In Q1 you can't say $10 million is the run rate because our construction projects really ramp-up in the second and third quarter of the year, that our growth projects that we're working on. So we're still within the ballpark of our guidance suggestion that we put out there, with the information that came out this week, and it will ramp up as the summer construction season heats up.

Hi everyone. Thanks for the call this morning. Alan, you guys have been very active since analyst day a year ago with asset sales, JV rationalizations and clearly a focus on deleveraging. I guess I have two questions stemming from all of that. The first is to follow up on Shneur's earlier question about your longer-term 5% to 7% annual EBITDA growth guidance. Just curious how to interpret your longer-term place in for periods beyond 2019, just wondering maybe how you or John will think about the outlook versus the forecast contained in the WTZ S-4 last summer?

Well the WTZ S-4 for last summer, I wouldn't pay much attention to the financial information. We had to do a fair amount of talking through that; that wasn't obviously meant for marketing purposes. Looking at our forecast today, again, back to our earlier point, over the next two to three years, we see capital spend at around $2.5 billion on expansion capital. We see our deleveraging and at the same time, we see this level of EBITDA growth of 5% to 7% range. So I really, wouldn't put too much weight on the WTZ document.

I would just say Chris, we are focused on delivering on both of those ends; both on the 5% to 7% growth as well as deleveraging. We're balancing that, and obviously being able to sell assets at high multiples is a pretty attractive way to get there. We're also very focused on making sure we have plenty of reinvestment opportunity to drive that growth of 5% to 7%. So far, I’d say we're comfortable about our ability to continue to face that capital. Projects continue to develop that are moving on nicely. A sizable project recently developed is the Regional Energy Access project, which is coming along very nicely with strong support.

As we get into the 2022 time frame, the deepwater cash flows will be significant because the FIDs for those projects are moving ahead, bringing new business through. It may seem speculative, but many projects are coming our way. We are doing well in managing that kind of growth rate and continuing to deleverage.

Okay, and one clarification on that John, just my own purposes, it's very clear you omitted any Transco rate case related impact on the formal 2019 guidance. As we think about 5% to 7% over the next couple of years, is it safe to assume that if you get a positive outcome there in that period of time, that's additive to that range or maybe puts you higher up in the range?

It would put us higher up in the range.

I guess that’s very helpful. My second question, I very much appreciate the presentation materials and something that we always acknowledged but illustrates clearly, I think it's Slide 13, it's just the significant non-cash items that are a 2% drag on EPS. I guess I'm just curious, are there additional transactions or impairments for restructuring that you could do to maybe trim some of those items for the benefit of EPS? Just we get a lot more questions from investors about EPS; I'm assuming you do too and I'm just wondering what more could be done on that front? Thanks.

That’s a weird commentary for a CFO to look for impairments. It is something that to the extent we could have, it would benefit our depreciation by lowering it since it's out of line with our maintenance capital. There's really not a lot we can do on that front, absent to the extent we partner on assets that we consolidate; that and that’s to move the assets from a consolidation to a non-consolidation type approach maybe partnering through JVs. That potentially could allow us to revalue assets and impair, bringing depreciation down. Anything short of that though, any of the tests or impairment is based on gross cash flows, and well a lot of these assets got marked up to really high-value back in the Access Midstream merger which was not a cash deal; it was a stock-for-stock trade but it forced us to revalue a lot of the Access assets at a very high valuation level on the books. The gross cash flow still exceeds those book values, so anything short of actually some sort of partnership or JV that would force some level of deconsolidation, that's the only thing that allows really to help bring that depreciation down.

Okay, that’s helpful. I know it’s a line of questions for you. The focus seems to fully change, and it seems like the reason [indiscernible] in Northeast maybe our structure [indiscernible] as well. So, just that was where I was -- I appreciate it.

Good morning. Most of my questions have been answered. I did have a quick one. Alan, you commented on the weak wet gas situation in Marcellus and Utica in terms of recent trends, and it looks like Blue Racer had a pretty tough quarter. How do you see all those impacts related to the pace at which your new West Virginia panhandle processing might fill off over the next couple of years?

I think Craig, the investment we have there feels pretty good about that filling up. As I mentioned earlier, we’ve got a lot of pads being turned online, we are really starting to see progress on that front. It doesn't take a lot, big as those plants are, to make significant headway. We have contracts coming our way that are shifting volumes our way. So feel pretty good about the TXP-2, the existing base capacity plus TXP-2, and we were able, as a result of this synergy, knowing we have excess processing capacity at the UEO, that prevents us from having to put any capital in place to build out in front of those increasing volumes. It helps preserve cash flows. I would say that gives us a lot more breathing room and allows for better capital efficiency as it relates to the OVM processing capacity. So, we intend to take full advantage of that.

Some -- just real quick. From my seat, I would say the biggest debate points among investors is capital allocation for companies in the midstream space. So I’m just kind of wondering how you guys look at that strategically, when you get together kind of bouncing growth, delevering, and returning cash to shareholders over the longer-term. I think you said kind of the -- to leverage target, but what do you think the right leverage is for a company with the asset mix of Williams? Is that something that should go below 4x, are you happy with being in the low 4s? Just interested in your thoughts here.

I would just say our asset mix doesn't have a lot of -- very little business that's marketing based; it’s not basis differential based, it's not the term optimization that gets you to often around the assets. We don't have that kind of variability per cash flow, I bet you can see that with the remarkable predictability to our cash flow streams, that continues to flow. I don't think we ought to be marked all the same, but I would say that ratings agencies have told us that on their basis, it's about a 4.5x kind of number to be BBB flat, and we want to be there confidently at that BBB flat level. For a target of 4.2x on a steady run-rate basis is what we're seeking because that happens to coincide with those types of level from the agencies.

If you guys are getting feedback from the investment community, do you really want to see something more of 4x, is that something that you would aim for in that case? Or do you think, well let's just kind of go with what the rating agencies are saying?

I would just say from my own personal perspective that I think the investment community seems to go in fads in terms of where they think the right leverage is. From our vantage point, keeping our debt costs down and capacity to flex when we need to is what we're targeting from our business trajectory. I think we think that's really the smart place for us. The market has to figure out who has volatility in their cash flows and who doesn't. That ought to be driving the number, that each company should aspire to — not just because somebody magically came up with a 4x number.

Okay. Well, great, thanks everybody. Great questions as always and we appreciate the opportunity to visit with you on this. Really excited about the continued very predictable way our business is running, and the way our teams are executing on projects. I look forward to speaking with you in the future and at the next quarterly call. Thanks.