威廉斯 (WMB) 2019 Q1 法說會逐字稿

Good day, everyone and welcome to The Williams Company First Quarter 2019 Earnings Conference Call. Today's conference is being recorded.

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

Thanks, Devin. Good morning, and thank you for your interest in The Williams Company. 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 will also mention that we 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 standalone analyst packet into the earnings release document, so we now basically have one document there 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 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. Well, 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 for the day.

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 prep -- to the presentation and take a look at our first quarter 2019 results.

Here 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 teams. And the results reflect very little direct commodity exposure. In fact, our first quarter 2019 gross margin reflects 98% fee-based versus only 2% of direct commodity margin. And 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. I'll have much more to say about the adjusted EBITDA performance on the next couple of slides, but you can see here that it increased 7% year-over-year without adjusting for asset sales.

And also you see really nice improvement of 16% for of 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 then lastly our very strong 1.7x dividend coverage also increased versus the prior year.

So really nice improvement on various earnings and cash flow metrics despite the impact of some significant asset sales.

And 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. So starting on the left-hand side of the table, if you start with the debt to adjusted EBITDA directly from the March 31, 2019, financial statement, you get to a value 4.92x. However, that metric includes about $727 million for the purchase of the remaining 38% interest in UEOM, which we funded partially with our revolver right at the end of Q1, but will be refunded with proceeds reserved at the closing of the UEOM-OVM JV that we've done with CPPIB, a lot of letters 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 4.77x. And then 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 for the Jackalope Gas Gathering transaction, the leverage metric falls to just over 4.5.

So 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. And so on this slide 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 increased with an over 20% increase in adjusted EBITDA, driven by top line revenue growth from new expansion projects including Atlantic Sunrise and Gulf Connector, really very impressive growth from the Atlantic-Gulf driven primarily by continued projects that have been going into service on a regular basis on Transco.

Next up, 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 volume 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 high single-digit growth in the Bradford and OVM areas.

But overall, very nice start to the year for the Northeast G&P.

And finally, we have the West, which is showing about a 7% decrease in year-over-year adjusted EBITDA after adjusting for its share of the asset sales described earlier. And 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 customer's 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 first quarter of 2019 versus the fourth quarter of '18, as you can see here on Slide 5. Of course, important to note that there were 2 fewer days in the quarter, which by itself is about $26 million or 2% of an impact.

The Atlantic-Gulf was up about $30 million over fourth quarter, driven by lower O&M cost and Transco revenues were higher related to Gulf Connector, but lowered due to Gulfstar One volumes caused by well maintenance.

Northeast G&P was pretty flat in 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 in Aux Sable and Blue Racer midstream. Recall that Aux Sable is the nonop interest in a processing complex in Illinois. And as we discussed in the past, the Northeast EBITDA growth in '19 is more weighted towards the second half of '19, and we'll be covering the outlook for the Northeast in more detail in a moment.

Finally, the West was pretty stable compared to 4Q of 2018. Revenues in 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 valuation margins.

And as you may recall, our fourth quarter '18 marketing margins were unfavorable, impacted by the same losses in marketing inventory. So as prices move up and down, the line fill valuation is something that swings up and down.

Lastly in the West although, we did see some nice sequential double-digit growth in the Haynesville, overall volumes were flat due to the severe weather in the first quarter of '19, again, from the Wamsutter volumes, which were down in 1Q from weather as mentioned earlier.

So generally Haynesville -- we had some nice growth in the Haynesville, but it's pretty well offset by the Wamsutter volume decline from the freeze-offs there.

In summary, 1Q adjusted EBITDA was within 1% of our business plan overall. And as we've said before we see the overall 2019 growth to be weighted more towards 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 guidance 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 5 important portfolio optimization transactions, including the Four Corners and DJ Basin transaction; the Brazos JV transaction; the sale of our Gulf Coast purity business; our Northeast JV that we've mentioned; and most recently, the sale of our Niobrara business.

So lots of moving parts since we had 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 Barnett 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 noncash charges that impact our EPS, so we've given more visibility into those elements.

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.

And 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 the producer activity in the region. So our teams are doing a really nice job of making sure 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 mode up there.

So 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. And when you factor in the new Northeast JV, our total contributions from JV partners this year [take off] another $120 million in addition to that $400 million reduction in the stated growth capital.

And when you consider 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 needs with operating cash flows and proceeds from these transactions.

The effects of our portfolio optimization transactions along with our lower capital expenditure forecast has had a favorable effect on our 2019 year-end book debt to adjusted EBITDA, which we now expect to be under 4.6x.

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 forecasted 15% CAGR for the Northeast area gathering volumes growth for 2018 through 2021.

Since then we've continued to work with our producer customers through 2 more forecasting cycles. And 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.

So despite this price decline, I am 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.

But most of this is on the backs of 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 a few of our producer customers have focused spoken on tuning their drilling CapEx directly to their free cash flows, and therefore, producer forecast at this point for 2020 and 2021 are very sensitive to forecasted pricing. I think very important to note there that a lot of the planning is done around forecasted pricing. And as prices change, we see producers shifting that, obviously.

Right now, I would say with the depression 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 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. And 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.

As a result, we don't believe that the current downturn in pricing is sustainable, giving the continuous growth in natural gas demand coupled with the discipline we have seen from the producer community.

And while Permian supplies are a needed resource to help fill the demand, we still have 2/3 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 that continues to grow.

While those fundamentals continue to support our steady and sustainable long-term growth, we do want to be transparent about the producer's forecast as they relate to our near-term gathering volumes and growth rate. Using the current detailed forecast from our producers, our gathering volume CAGR is expected to be a very impressive 10% to 15% growth through 2021, and while our EBITDA CAGR would still come out at or above 15% through the same period.

Also on this front, I'm 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.

So we're encouraged to see the level of EBITDA growth of our Northeast G&P business 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.

We've had 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 partner who also owns and controls 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 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 period.

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, and those new higher rates went into effect on March 1. So we're currently 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 2 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 counterparties at this time.

I can tell you that the settlement negotiations are likely to continue for many months and could extend into next year. We're hopeful that a settlement can ultimately be reached without the need for litigation and that the settlement would include the $1.2 billion emissions reduction investment opportunity.

And we continue to present any upside from the rate case -- sorry, continue to not have any of that upside built from the rate case reflected in our financial guidance.

And let's also touch on the status of Transco's major growth projects here. Lots of news out there these days and questions regarding the effect that the recent presidential executive order might have for our projects. Obviously, Williams supports efforts to foster coordination, predictability and transparency in the federal environmental reviews in 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 are appreciative of the administration's efforts and in strong support of a sustainable approach to ensuring consistent application of EPA's regulation.

However, we know that any major shifts in policies coming out of 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 great job of navigating those.

And so 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 that allow these regions to continue to lower the greenhouse gas emissions.

And to that end, we continue to press on the 20-plus Transco projects we currently have in development, including the most recently announced Regional Energy Access project. The binding open season for Regional Energy Access was extended from April 8 to May 8 to give shippers additional time to get the approvals they needed not for just the indications of interest, but for binding commitments.

And we have been impressed with the interest the project has garnered. We are targeting a final investment decision in the third quarter of this year with prefiling to follow. And next up, 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 took action to address oil and gas development laws. Ultimately, the new legislation seems to be a much more balanced approach than what we saw last fall with the failed Proposition 112, with the vast majority of oil and gas activity occurring in the industry friendly Weld County area. We welcome the shift in 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.

Here in early April, we started up our new 200 million cubic feet a day Fort Lupton III cryo. That train is running very reliably and great job by the teams getting that started up safely. And construction is progressing very nicely on our Keenesburg I cryo that should be online in the third quarter of this year. And in February, we signed up another new package of gas along with NGL marketing rights, right in that same area where we continue to develop infrastructure. So really very pleased right now with the strong demand for reliable and gathering processing services in the area, and we look forward to continued growth and support for our NGL marketing businesses including the Bluestem pipeline project and associated upgrades at Conway.

And next on to deepwater. Last but not least, we have seen a steady increase in activity in the deepwater Gulf of Mexico, where a substantial new discoveries are being made in close proximity to our asset. 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 cost and cycle times low by utilizing existing infrastructure like ours.

This year, we'll see EBITDA contributions from our Norphlet project, including those from the purchase of the Norphlet pipeline and additions to our Mobile Bay processing complex that we did last year, and that is going to get paid for. Actually our Norphlet Pipeline purchase gets 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.

So as I promised on the introduction side, we tried to keep things brief today, but we're pleased to be able 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.

(Operator Instructions) We will now take our first question from Jeremy Tonet of JPMorgan.

Wanted to start off with the Northeast G&P, and was wondering, if maybe you could 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 kind of 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, Jeremy, thank you. Yes, in terms of cadence, I would just say right now, we've got a lot of activity, a lot of wells being -- and pads being turned into line right now as we speak, actually here in the last month. So a lot happening out there right now. All over the place both in the Northeast and the Southwest and so a lot going on, on that.

I would say in the Utica area, the Encino team there has just now taken over operations of that area, transition from Chesapeake. And that we're really working closely with them to have kind of the same kind of integrated approach to development and growth development that 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 the kind of cadence there I would just say certainly, Cabot continuing to lead the way with development with 20% kind of growth. And so I would say that Northeast PA continues, they have continued to invest with -- or support our expansions of -- further expansion on our gathering systems out there. And of course, are very interested in additional takeaway capacity out of the area, given the big reserves and the low cost reserves they have in the area. So I would say in the Northeast, there really hasn't been anything other than just continued, steady performance by Cabot, and we're starting to see that kind of spread in to some of the other areas as well, like in the Bradford area. So Northeast though, I think is very predictable and steady. The areas that have more, I would say, volatility in terms of ups and downs and perhaps being a little more reactive to prices is in the wet gas areas, like I mentioned earlier, both the Marcellus wet and the Utica wet. And a lot of that, I would tell you, is driven by pretty sharp price -- realized price decline on NGLs that were associated with the Mariner East up and down and of course, now hoping for expanded capacity out of their own Mariner East 2. So I would say that the pricing forecast on NGL have been difficult to predict. And of course, the gas takeaway situation, particularly with MVP, has been pushed back a little bit as well. So I think those things will resolve themselves as we get in -- obviously, as we get into 2020, I think those things will resolve themselves, but we are seeing those 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 build-out though, continues to be pretty robust for both the Southwest PA and the Utica area, a lot of new capital. But we're finding ways to really trim that back and have that capital come on just in time as the production comes on, and so that's what you see reflected in some of our capital pullback and reduction in capital that you see here in our guidance.

That's helpful. And turning to UEO OMV, the combination there. I was just wondering if you might be able to provide a little bit more detail as far as some of the synergies (inaudible) capital efficiency improvements.

Yes. Great question. Really 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 investment that was going to be required there to continue to operate that facility and to expand it. And 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. And so we'll be taking those liquids over to the excess capacity -- big excess capacity that exists at the Kensington fractionator.

And so they were sitting there, a lot of latent capacity on the fractionation side and better markets there at the Kensington area. So effectively allows us to shift our focus of growth for fractionation and reduce any investment required at Moundsville and [would] they take that capital out of our capital plan. So that's the simple side. On the more complex side, we also are looking at ways to take advantage of the access processing capacity that UEOM enjoys. And we're starting to run up on the capacity constraints there at OVM. And if growth continues there, we'll be looking for ways to move volumes over to UEO as well. So those are kind of some of the obvious issues, obviously there's management consolidation and overhead consolidation that's beneficial to us. But a lot of it really just has -- relates to being able to take capital out of our plan that would have otherwise been in there.

That's really helpful. And 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? And when do you see kind of the path forward at this point as far as permits and when construction could start there?

This is Michael Dunn, I'll take that. We absolutely think that NESE is a key piece of the puzzle in New York City and New Jersey metroplex to reduce emissions, especially CO2 emissions, it's very dramatic in regard to the emissions profile of the fuel oil that's currently being used and converted to natural gas up there. And we're 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 [birth] certificate for that project any day now. And the 401 certification deadline in New York was mid-May and then 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 fashion.

We will now take our next question from Shneur Gershuni of UBS.

Just sort of 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, does that sort of change 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?

Yes. Great question, Shneur. And 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 in to UEO, so those gathering volumes would have already been in there, so there's really not any change on that UEO. It's primarily just the fractionation of processing facilities downstream to that. So that's really no change from 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 being able to balance between the 2 processing complexes and the liquid. So actually a lot of the capital is even more of a (inaudible). So a lot of the gathering capital really won't change that much. If you think about that it's really on the processing and fractionation capital that we'll be able to shift volumes into areas that -- not have to put expansions into like we would have to others.

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. And I'll maybe have John Chandler take that in terms of the -- where we would go with that. But yes, as we've 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. And so obviously, as we can have high grade our investments that improves and bring in synergies like we're doing on these JVs. But generally that $2.5 billion to $3 billion is what we think it takes to grow the 5% and 7%. And I'll let John talk about the funding.

I think that's fair. As we look forward in our projections today using this $2.5 billion, use that as the number type of expansion capital. And as we look to our forecast, we're able to fund that completely and entirely through excess cash flow. And 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 that supports that kind of EBITDA growth.

So will there -- effectively once you hit your leverage target, will there then can be room to consider share repurchase business [well also]?

I -- we'd have to talk about that once we get there. There's still work to do, obviously between 4 -- under 4.6 to 4.2, there's 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, Shneur. I would just say on that front, we'll see what the markets look like when we get to that point, but -- and so it's kind of hard to answer that because we're speculating on what the returns would be on that investment versus our other investments. But I can tell you we're constantly allocating out capital return project that a lot of the industry would accept. And so I think there'll be a balance there between increased capital investment opportunities as another thing we can do with that capital. And as I said, we're constantly allocating a way -- projects today as we continue to press on deleveraging the business.

And one last question, if I may. Your excitement level about the Gulf of Mexico seems to be increasing. You sort of touched on it in your prepared remarks, but I was just wondering if you can sort of expand on the opportunities that you see there, and how we can -- should be thinking about it on a go-forward basis?

Yes. I would just say, the opportunities are getting to be so plentiful that kind of getting hard to keep track of honestly, but some of the very certain opportunities exist around the Gulf West -- or our operations around the Perdido area, obviously the well perspective out there is going to be a big mover for us. And Shell just announced a little bit earlier this month -- or sorry in April, the Blacktip discovery, which is also another very large discovery in that Perdido belt area. And then to the south of that of course, the Mexico Perdido is even a much larger kind of order of magnitude opportunity that we're extremely well positioned for. So on the Western Gulf, it's going to be a matter of maximizing our return on the investments. There is plenty of production to fill up our existing capacity and then there's more. And so 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 there today.

If you move over to Gulf East, of course, really excited about the Ballymore prospect that will likely get produced across the -- Chevron's Blind Faith platform and that's also a very large find there. And again, just big, free incremental cash flows coming our way with very little-to-no capital on our part, so we're excited about that. And then the Norphlet prospect, while we kind of thought that was almost singular as an investment originally, and we liked the returns just similarly 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. So lots going on. In the central Gulf, lots of new opportunities. The LLOG-Repsol JV will bring some promise to us in the area and a lot of new development going on there as well. So I'm not even getting into the multitude of smaller projects that are coming our way, but 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 or -- as they were enjoying prior to '14, there wasn't so much focus on the use of existing infrastructure to keep cost down. But now with the lower prices we're seeing a huge focus on utilizing existing infrastructure and therefore, that means we're not having 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. And so I would say, if I was going to describe one big change from the last time we start the deepwater take off, that is really it. That there's this intense focus on the utilization of existing infrastructure. And of course that -- when you are -- already have a lot of the big gas infrastructure in the deepwater that bodes very well.

Alan, if I could add to that on the Norphlet opportunity. That was a great negotiation for us to have with Shell there where we acquired the pipeline that they built, it was pre-negotiated with a return, and we're obligated, obviously, to move their gas to shore to our Mobile Bay facilities where we have percent of liquids contract with them to process that gas. But the strategic value there additionally to us is the fact that, that pipeline won't be full. And from day 1, we can go out and acquire other business to bring through that with subsea tie-backs into the Norphlet pipeline that we'll purchase upon first gas movement there. So a great opportunity for us to take advantage of that facility that has already been built, so the construction risk is taken away as well as a timing risk has been taken away because we don't pay for it until the gas flows.

We will now take our next question from Christine Cho of Barclays.

You guys have talked about wanting to consolidate Northeast for some time, and obviously the UEOM transaction took 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. And I would just say the -- 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 made sense for us on that. And so I would say lots of opportunity. But we remain patient and will remain patient with making those combinations. So -- but I do see some opportunity just contractually to continue to find ways to utilize common facilities out there and I think that's a mediocre step in the middle, if we can't reach agreement on a broader transaction.

Okay. And then you guys are tracking to get to your targeted leverage faster than planned, should we think that there are any other non-core assets that you are 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 kind of transactions in a way that don't dilute our future, and our -- and stand in a way of us accomplishing our strategies, then we'll continue to look for those. But we don't have anything specific on the drawing boards and I think as we've said before, I think looking to our strategy and looking to how things link in our asset base is not because we have some written rule that says we have to have a downstream business for it to be a core asset. But when it comes to placing capital, new capital, and it's competing in this capital allocation process that we're constantly running. If it doesn't enjoy the downstream benefits and the coupons that flow from the downstream benefits, the incremental returns just don't stand up. And so Niobrara is actually a perfect example of that. The returns just on the standalone G&P basis there just didn't stand up well within our capital allocation program. So we had both partners and customers frustrated with our lack of interest in investing at those return levels. And it wasn't for any reason other than it just didn't stack up within our capital allocation process, and so that's why we are fixated on that, it's just because those areas that are in growth tend to drive those higher returns and therefore make it through our capital allocation process.

So I think that's about as much as I can tell you. Do we have our sights on anything in particular at this time, the answer is no.

I would also say though that -- I would also say though there is obviously cheap money looking for opportunity out in the marketplace and very similar to our Four Corners assets, we get approached by the market all the time on assets. So again, to Alan's point, while we don't have anything specific thing targeted, we're constantly being approached.

We will now take our next question from Gabriel Moreen with Mizuho.

I just had a quick question on the Transco rate case and some of the associated details around that. It seems like the timeline there has been extended around settlement discussions. Can you just talk a little bit about the decision to kind of keep going with settlement discussions and I think extend the timeline here fairly considerably? I assume you're pretty confident in terms of your own position there. So why not a move to maybe litigate a little bit earlier than end of 2020?

And related to that, the cap -- the emissions reduction spend at Transco is there -- 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?

Yes. I'll take that. This is Michael. 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 there in regard to trying to reach settlement. So we think it's prudent to continue that process until we reach impasse with our customers, but we're certainly not there yet so we're rapidly working with them to try to come to a settlement that both sides appreciate and like. But it certainly doesn't mean we won't be willing to litigate that if we feel like we've reached impasse and certainly the administrative law judge will assist us in getting there, hopefully quickly, so that we can, you know, move on to the litigated path if settlement is not where we ultimately end up. But we would love to have a settlement with our customers there, we think it's the proper way to hopefully to achieve a good outcome for both sides. But we're not afraid of the litigation path as well.

Specifically on the emissions reduction, so the way we've contemplated that, it would 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. And it really just allows us to do that as if we were going through a rate case, so to speak, without having to go through a rate case to be able to increase those rates as we deploy that capital to reduce those emissions along the Transco pipeline systems. And so if ultimately we don't get the emissions tracker that would make it more likely that we would have more rate cases coming to be able to accommodate those emissions reduction projects within our rates.

Great. Maybe if I can just get more of an update sort of on Bluestem and how discussions are going on that, if their recent Waha prices have been motivating customers a little bit more. And to what extent you're looking at partners there and where it may stack up, sort of, on the returns profile within your capital backlog?

Yes, this is Chad Zamarin. Thanks for the question. I would just say we continue to work on projects in the Permian to Transco markets. But you've seen recent dislocation in basis from the basin, obviously, to the coast. But if you look at the forward curves, I think, the market has been a little slow to recognize that, that might be long-term sustainable, so we're going to be really, I think cautious in ensuring that any project that we would proceed with is one that has really solid fundamentals and economics. I think 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.

And ultimately, I think what's important to us is to continue to build Transco's market connectivity both on the supply and on the demand side and so we believe those volumes ultimately want to get to the best markets and so we think Transco offers those very best markets. So again we continue to explore participating in a project from the Permian to the Gulf coast. We have volumes with our partnership with Brazos Midstream that we can leverage for the purpose of benefiting and improving a project. But again, I think the economics that we've looked at, at least to date, on the projects that have gone forward and that are being contemplated haven't yet met our expectations alongside the inventory of opportunities that we have. And so we'll continue to work it. And again, I think is the most important thing for us will be that we make sure that Permian gas has a good home to come to along our Transco markets.

We will now take our next question from Colton Bean of Tudor, Pickering, Holt & Co.

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

Yes, I know, I think we continue to see quite a bit of flaring 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 pipe project comes online. We've seen significant volumes shut-in in the alpine high area. And so we have seen I think restrictions associated with gas prices in Waha. So I think it -- we get a lot of questions around with as large as the basis is why we haven't seen a stronger move towards an additional project. I think what we're seeing is this takes -- as Alan mentioned in his comments, it takes a lot of time and effort to create infrastructure that can move all the way from West Texas to the market. And so I think we'll continue to see a desire to reduce flaring. But the options today are either shutting in or waiting for infrastructure to be built which takes some time. We think another project needs to get built but again if you look at the curve, the forward curves from basis, Waha to Henry Hub right now, those prices don't support an investment in a long-haul pipeline. So until we see producers and end market users willing to step up for longer terms and better economics, I think we'll continue to see challenges in the basin.

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

This is Michael. Is not really -- it's more of 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, it's just a timing issue of activity.

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

Well, and I'm not going to be predictor of go-forward rates with the exception of saying that it's lumpy because of timing and specifically with turbine overhauls, they're pretty expensive, a couple of million dollars to do 1 turbine overhaul and those have to get done at certain intervals of runtime hours and so we have to accomplish those when we hit those runtime hours, and so it's highly dependent upon the runtime of the equipment, for example, when we have to do would those, and if we have emerging problems we have to go take care of. And I would also say in the 2018 quarter, we also did a lot of work on our reciprocating compression on the Transco system that had to be accomplished as well. So it's just a timing of overhauls aspect and it's highly dependent upon runtime.

Understood. And just a quick final clarification here. For the $400 million reduction of capital program, I think you all had noted previously that around $90 million was associated with Jackalope. So is the balance of the entirety there solely attributable to the Northeast? And then as you 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 that you outlaid?

Great question, Colt. First of all is a combination -- on the last part of your question, it is a combination of stuff getting pushed out as well as ability to not have to, for instance, continue to expand at Oak Grove and Moundsville. So yes, it's getting pushed into '20 but you'll see some of the benefit of synergy show up in '20 would offset that, if that makes sense to you. And then finally, on your question of the $90 million Jackalope, $400 million elsewhere. Well, I'd just say a lot of moving parts, of course we have a little bit of cost in there for getting on with the fractionation at Belvieu as well as Bluestem who's going in there, some capital coming out of the Northeast. And some lower capital for the year just as these projects -- we always have a lot of contingency built into these projects and as those push out and get closer, you saw we advanced one of our Transco projects into 2020. And so we're actually seeing really good performance on that front. But for the most part it is coming out of the Northeast, but not all.

We will now take our next question from TJ Schultz of RBC Capital Markets.

On the executive order you guys highlighted, what's your expectation from the DOE, is it worse to submit reports just on timing to get more clarity around that, and any input you all are having on that process.

Well, I would say on the presidential executive order, first of all, we were really impressed with the work that was done by the various attorneys, staff attorneys around EPA. I think everybody recognized that the -- some of the so called "guidelines", and I'll use quotes around that, some "guidelines" had been put in place during the Obama administration that had become treated almost like rules by the state and in fact there's never really been a regulatory process to establish that.

And I think the -- appropriately the EPA administrators, regardless of which party affiliation you're interested in, I think they thought that, that was not proper administration and regulation and so they're trying to bring clarity to that. And that's exactly what we've been asking for. We haven't been asking for easier regulations, we've been asking for clear and consistent regulation. And that's exactly what we thought the order tried to address without overreaching towards any one particular project. So it's something that needed to be cleaned up and if you really dig into that it's actually a very astute and detailed approach to it that we really applaud. I think it's exactly big step in the right direction, and it's obvious to us there was great experts involved in that. So while I don't see it being a miracle cure for any one of our particular projects that we have out there right now, I do see it as a big step in the right direction for bringing clarity and consistency between how the states and the Feds deal with Clean Water Act regs within the EPA. So pretty impressed frankly with the sophistication of that work.

Okay. Makes sense. Just one more, you've mentioned Mountain Valley a couple of times, maybe ignoring timing on in-service, they've built a lot of that project. Assuming they get to Station 165, you talked about synergies, 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 to you all.

Sorry, just to clarify, you were talking Mountain Valley pipeline, is that correct?

Yes, sorry about that, Mountain Valley pipeline.

Okay. Yes, thank you, this is Michael. You know just seeing what the Mountain Valley pipeline backers have said about their project, obviously they feel certainty in regard to completing their project. And we're obviously watching that very closely, along with them. And ultimately, we'll get Station 165 area and there very likely should be take-away opportunities for us from that point on the Transco system once that project gets closer to some certainty there. But 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, and we certainly think there's opportunities to do that.

We will now take our next question from Jean Ann Salisbury of Bernstein.

It looks like latest flows into Transco from the Northeast Marcellus are around 4.5 Bcfd including Atlantic Sunrise, is that effectively the max capacity for Transco there? Is there any way that you could take more gas and get paid for it with just compression or anything like that?

You know, I'm going to say there's -- just to remind everybody on that. Transco's capacity is fully sold, so it is consistently sold out, I think, Jean Ann, you have the (inaudible), and so really what we're talking about is just interrupts, is just lows and how much we can physically flow during the period, and that's very dependent on local loads, where the gases need to be delivered to. And so there's a lot of variables that go into play there. But I would say, generally, we are constantly maximizing capacity out of that basin right now because the margins support that. But a lot of that is managed by the shippers, in other words, they're the ones dictating where they want to move the gas to and from and so a lot of that is [dictated] by them. But, I think that's -- we're -- I would say every day, we're optimizing as much as we can move out of that area.

Okay. That's helpful.

(inaudible) are staying full, like Atlantic Sunrise has virtually been full almost since day 1, so that does bode well for the future opportunities to move additional expansion volumes out of there with new projects.

You know Regional Energy Access, Jean Ann, Regional Energy Access though takes advantage of a lot of the existing infrastructure as does the Leidy South project that we're working on for -- excuse me, for National Fuel Gas and for Cabot and so there is obviously some pretty easy expansions out of the area, relatively, the project teams that are working on that wouldn't clarify -- wouldn't classify it as that. Relatively. We've got a lot of compression we can do, and little bit of looping to do to add capacity out of that area.

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

I would say in the Haynesville we bump up against the top end there quite often as the well pads come on. We did max capacity there last year and continue to find new volumes coming in there that put us right at max capacity, so we're pretty maxed out at Haynesville from time to time, it's highly dependent on when the pads come on and then the steep [climb] on those wells.

And then the Eagle Ford we continue to have new well connect opportunities there as well, and we continue to expand our systems their as needed for the producer customers out there. Most of that requires additional compression when we bring that online, and some new wells connect capital as well and possible looping. So it's highly dependent upon where the producers are drilling their pad. A system like to Haynesville, that system actually has a south and a north component to it and so while you might see one part of the system get loaded up, the southern part may be more than the north sometimes, or vice versa, that really dictates. So it's not like it's a processing plant where you just have a fixed amount of capacity through the plant. The system, the capacity is very dependent on where the gas goes up. But our teams have done a really nice job out there working with other midstream operators in the area to use up capacity to be able to cross haul between the systems and they continue to do that. On the Eagle Ford, we would remind you that, that is a cost of service agreement and so that as we add capital there that gets covered in our rates where the Haynesville is not that, it's not that setup.

We will now take our next question from Mike Lapides with Goldman Sachs.

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, meaning got stuck in the court system, bogged down for a lot longer or cost creep inflated to a point making it untenable. How do you think about the solutions that Williams could offer into Virginia North and maybe in South Carolina? And the ability, the timeline to realize some of those solutions?

Yes. Michael, obviously, it's topic that's been getting a lot of discussion. We have a lot to offer in terms of distributing the product -- the gas to market, whether it's helping what would be the ACP Eastern system or moving supplies to them. We have -- we do have tremendous amount to offer with our existing right of ways. MVP is more just kind of a downstream issue so to speak because obviously they got to cross the Trail with those supplies. And so that's really the struggle there. But, I would say we have a lot more to offer ACP in terms of meeting their market distribution goals. And as the MVP, they need -- they're going to need some market distribution if they do get across the Trail and we're well-positioned to help out with that. So that's how I describe that. Obviously in this environment I think it's important for all of the industry participants to try to utilize as much existing facilities as possible, keep the cost down and that's what we're very focused on in both those cases.

But if ACP for some reason or another didn't get completed, how much new infrastructure, or new steel in the ground, how much significant new pipe would you have to build especially to get it -- get the gas into North Carolina? I'm just trying to think about the infrastructure requirements and the timeline to deliver them.

I would just say we have a lot of (inaudible) routes already in to some of those markets but it is significant in terms of the (inaudible) existing facilities, but it would be pretty significant investment required, and it's very dependent on where the supply comes from. So a lot of variables here depending on where the supply comes from, but if you just showed up with the supplies along that 165 to 195 corridor we have a lot of ability to help distribute that gas into those markets.

We will now take our next question from Justin Jenkins of Raymond James.

Just one follow-up from me. Just if you take the 1Q run rate for CapEx we're a bit below the full year guidance, so is it more balanced throughout the rest of the year here? Or is it back-end loaded? Maybe just some help on the cadence of CapEx if you could?

Yes. This is Michael. I would say, Q1, you can't take that really as a run rate because our construction projects really ramp-up in the second and third quarter of the year with our growth projects that we're working on. So I would say we're still within the ballpark of our guidance suggestions 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.

We will now take our next question from Chris Sighinolfi of Jefferies.

Alan, you guys have been very active since analyst day a year ago with asset sales, JV rationalizations and clearly a focus on deleverging. I guess I have 2 questions that stem 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 phrasing? For periods beyond '19 just wondering maybe how you or John would think about the outlook versus the forecast contained in the WTZ S-4 last summer.

Well, the WTZ S-4 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. So as we look at our forecast today -- again back to our earlier point, as we look at our forecast today over the next 2 or 3 years, and we look at a capital spend of around $2.5 billion on expansion capital, again we continue to see a deleveraging and at the same time we see this level of EBITDA growth that runs in the 5% to 7% range. So I really wouldn't too much put much weight in the WTZ document.

Yes. 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, and we're constantly balancing that. And obviously, being able to sell assets that are well at the high multiples is pretty attractive way to get there. But we also are very focused on making sure we have plenty of reinvestment opportunity to drive that growth, that 5% to 7% growth. And so far I would say, feel very comfortable about our ability to continue to place that capital. And, you know, projects just continue to develop that are moving along pretty nicely. And within this period I would tell you that the 1 sizeable project that's developed is Regional Energy Access project, that's come along very nicely and with a lot of strong support all of a sudden. So I think we're really feeling pretty good about the high return investment opportunities that continue to come. And as we get into the 2022 timeframe, the deepwater -- this isn't speculative on our part, the deepwater cash flows there are going to be pretty big because the FIDs for those projects are moving ahead and a lot of that business will be coming to us. And so while that's hard to predict exactly the size of that and exactly how much, those projects are out there and are coming our way.

So, anyway, feeling very good about the ability to see that kind of growth rate and continue deleveraging, but we are advantaging both of those as we think about transactions.

I mean obviously we continue to see -- even though we've softened somewhat maybe our long-term view of growth in the Northeast volumes from 15% CAGR to 10% to 15%.

Again we still see robust EBITDA growth coming out of the Northeast. We've got a number of projects, if you look in our slide deck in our appendix, number of Transco projects coming on the end of this year, next year that will be adding to EBITDA. And of course, it goes without saying the DJ Basin assets that we have acquired last -- late last year there is a significant ramp-up in growth coming from that as well.

Okay. And 1 clarification on that, John, just for my own purposes, it's very clear that you've omitted any Transco rate case related impact on the formal '19 guidance. But 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.

Okay. And then I guess -- that's very helpful. And my second question, very much appreciate the read out of the presentation materials and something that we've long acknowledged but illustrates clearly, I think it's Slide 13, is just the significant noncash items that do present a drag to EPS. And I guess, I'm just curious are there additional transactions or impairments or restructuring that you could 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 to, and I'm just wondering what more could be done on that front?

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

We will now take the next question from Craig Shere of Tuohy Brothers.

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

Yes. I think, Craig, the investment we have there, feel pretty good about that filling up and it is, as I mentioned earlier, we've got a lot pads being turned online and so we're really starting to see that come up. It doesn't take a lot when it's as big as those pads are to make progress on that front and we have some 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 the synergies and knowing we have excess processing capacity, the UEO, that takes -- puts us in a position to not have to prebuild any capacity out in front at Oak Grove any further, so the synergies or the -- as I mentioned earlier, one of the nice things about that synergy is it prevents us from having to put capital in place to build out in front of those increasing volumes because we do have alternatives about where we can ship those volume to but preserve the cash flows from it. And so I would just say that gives us a lot more breathing room and allows for better capital efficiency as it relates to the OVM processing capacity, and we intend to take full advantage of that.

Sounds good. So your TXP-2 is basically contracted up, the slowdown's not really going to impact it, but you're derisked on the fact that you don't need new capital because you have the ability to work between basins.

Right. Correct.

We will now take our next question from Timm Schneider of Citi.

Just real quick. From my seat, I would say the biggest debate points among investors is capital allocation for companies in the midstream space. And I was just kind of wondering how you guys look at this strategically when you get together kind of balancing growth, delevering, and returning cash to shareholders over the longer term. I think you said kind of that 4.2x leverage target, but what 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 kind of being in the low-4s? Just interested in your thoughts here.

Yes. I would just say our asset mix is we don't have a lot -- right, we have very little business that's marketing-based, it's not basis differential-based, it's not the term optimization that gets used often around the assets, which is trading around the assets. We don't have that kind of variability to our cash flows and I think you can see that with the remarkable predictability to our cash flow streams that continues to flow. So, no, I don't think they ought to get marked all the same, but I would say that the rating agencies have told us that on their basis, it's a 4.5x kind of number to be BBB flat, and we want to be there, be confidently there at that BBB flat level. And so that 4.2x mark on kind of a steady run-rate basis is why we are seeking that because that happens to be coincidental with that BBB flat from the rating agencies.

Got it, but on the sense I guess if you guys are getting feedback from the investment community, do you really want to see something below 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?

You know I would just say from my own personal perspective on that. I think there tend to be fads that move through the investment community. And I think from our vantage point keeping our debt costs down and the capacity to flex when we need to is what we're targeting from the business trajectory. And I think we think that's really the smart place for us. And I think the market has to figure out, and it should figure out, who has volatility in their cash flows and who doesn't, and that ought to be driving the number that each company should aspire to, not just because somebody magically came up with a 4x number.

There are no further questions at this time. I would now like to hand the call over to Mr. Alan Armstrong for any additional or closing remarks.

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. So look forward to speaking with you in the future and at the next quarterly call. Thanks.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.