威廉斯 (WMB) 2017 Q4 法說會逐字稿

Thank you for standing by. Welcome to the Williams and Williams Partners.

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I'd like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead.

Thanks, Chris. Good morning, and thank you for your interest in Williams and Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include press releases and related investor materials including the slide deck that our President and CEO, Alan Armstrong, will speak to you momentarily.

Joining us today is our Chief Operating Officer, Micheal Dunn; and our CFO, John Chandler. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks and you should review it. Also included in our presentation materials are various non-GAAP measures that we've reconciled to Generally Accepted Accounting Principles. And these 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, good morning, everyone, and thank you, John. First of all, I'll just say, these are going to be a little longer comments than usual since there's a lot of issues that we'll want to discuss this morning. So I'm going to jump right in. I'm going to begin by saying how pleased I am with the organization's strong execution in '17, a lot of notable achievements. We safely and in a timely manner delivered on Transco's Big 5 projects, which is Gulf Trace, Hillabee Phase 1, Dalton, New York Bay and the Virginia Southside II, and we exceeded the midpoint of our guidance range for adjusted EBITDA, and actually exceeded the top end of the range for distributable cash flow and cash coverage ratios.

And finally, we were able to bring CapEx spending in slightly below the midpoint of the range. Our teams achieved these impressive results which include improvement in year-over-year adjusted EBITDA for both the fourth quarter and the full year '17 despite the impacts of Hurricanes Harvey, Irma in May, and while executing crisply on $2.3 billion in asset sales. And if you go back to September of '16, it's actually $3.3 billion in asset sales.

As you'll recall, a strong foundation was laid with the financial repositioning we executed in January of 2017, which positioned the company to fund our attracted slate of fully contracted large-scale expansion projects without the need to access public equity markets for projects included in our current forecast. And now we are providing further insight into 2018 where we look forward to a full year revenue contribution from our Big 5, as well as contributions from our Atlantic Sunrise project when it is placed online later this year, along with the associated growth in the Northeast gathering volumes upstream of that.

We are excited as ever about our opportunities across the asset base, which we see driving continued growth for 2019 and beyond. And so for today's relatively long call, we're going to hit a recap of our performance for fourth quarter and full year 2017. We're going to hit the 2018 financial guidance, and we are going to take a brief look at the types of opportunities we see driving our growth into '19 and beyond. And just to remind you, we are planning an Analyst Day event in May where we'll dive deeper into our growth drivers for the future.

But for now let's move on Slide 2 and review the fourth quarter. So according to our GAAP results, which included some large one-time events related to the recent federal income tax reform, Williams C-Corp level reported fourth quarter net income of more than $1.6 billion, a $1.7 billion improvement from fourth quarter of '16. This large improvement was driven primarily by the remeasurement of Williams deferred tax liabilities to reflect anticipated lower future tax payments, and this resulted in a $1.9 billion gain at the GAAP level. But it's not quite that simple when it comes to the impact of tax reform, as we also had to take a $713 million noncash charge at WPZ related to tax reform of Transco and Northwest Pipeline.

I'll go further into the tax reform impact on a regulated pipeline a bit later. But for now, I'll just say that, generally speaking, we had to book an estimated regulatory liability of $713 million for possible future impacts on our cost of service rates, resulting from this tax reform bill.

Even though this is a big number, it's likely to only affect our future actual cost of service rate case calculation by a relatively small annual amounts as it gets spread over a period that could be 20 years or more, and is one of the many variables that impacts the ultimate rate that we charge for our max rate tariff service. To that point, given higher integrity expenses and maintenance capital expenses at Transco, we still expect to file a rate increase on our cost of service rates even after taking into account the effect of this change in the tax liability.

So let's move to the performance of the business in the fourth quarter, where WPZ's adjusted EBITDA was up $84 million or 8% when you exclude the NGL-Petchem businesses that we sold. This increase was driven mostly by our more than $100 million increase in fee-based revenues. These came primarily in the Atlantic-Gulf and our West segment.

And with that, let's move on Slide 3 to look at the full year of 2017. So even for the full year, those large fourth quarter tax reform related items played a key role for the GAAP results. But there were a few other drivers, including about $1.3 billion in gains we had on the Geismar and Permian JV sales. And then looking at adjusted EBITDA, WPZ was up over $200 million or about 5% versus '16 when you exclude the former NGL-Petchem businesses that we sold.

You can see in the graph where all 3 of the segments show improvement for the full year. Atlantic-Gulf saw increased adjusted EBITDA driven by the Transco expansion projects and increased volumes in the Eastern Gulf, partially offset by higher O&M expenses, as we continue to do quite a bit of asset integrity work and hydro testing on the main lines along the Transco system.

For the full year of 2017, results for the West benefited from lower cost. Growth in basins like the Haynesville, and higher commodity margins that were partially offset by the loss of results from the sell and trade of our DBJV trade with Western Gas and Anadarko, and the Northeast realized added benefits from the growth in the Bradford area with increased ownership from the various Bradford County systems that came with that trade I just mentioned. Positive results on our Susquehanna and Ohio River systems were offset by lower volumes in the rich Utica and our non-operated interest in the UEOM joint venture. So up there in the rich Utica area, we continue to see declines in that area. As you'll recall, we own both a rich gas gathering system, and then we own a 62% interest in the non-operated interest in UEOM up there.

In the Northeast, we consistently spoken of 2017 and '18 as transitional years for Northeast volumes. During '17, we started to see step changes, and take away capacity in the southwest part of the play that are beginning to unlock the growth potential of these unmatched natural gas reserves. And of course, we've also seen a lift in NGL prices in that area that's really spurred a lot of drilling in the southwestern part in the rich part of Marcellus play.

Moving on here to Slide 4. Here, we've recapped some of our recent achievements as we continue to build long-term sustainable growth in the business. It certainly was an impressive quarter and full year for the Transco team. The Big 5 projects that we've referenced many times added approximately 25% pipeline capacity to Transco, which is saying something given the size of Transco to start with. The final 2 of these Big 5 projects, New York Bay and Virginia Southside were placed into service, as planned, in the fourth quarter.

Also, in the fourth quarter, our West team saw higher volumes in 8 of the 10 gathering franchises, led by continued growth in the Haynesville. In the Northeast, our exit rate gathering volumes were up 600 million a day or 9% over 2016, as the de-bottlenecking of the Northeast is just getting started. And a portion of this volume growth is contributing to higher utilization of our Ohio Valley Midstream processing capacity, where we now expect to expand that facility by an additional 400 million a day, supported by strong customer volume commitments, and driven by this continued rich Marcellus drilling activity.

We've already seen the impact of the 5 major projects this year, which added over 2.8 Bcf a day of new capacity, and this was really on these projects or demand-driven projects on Transco. And this new capacity enabled Transco to set 1 day and 3 day delivery records in January. All of this is before we realized the benefits of the most significant expansion in Transco's history, the Atlantic Sunrise project, which continues to make great progress.

We have been dealt a challenging winter on the Atlantic Sunrise project. But a tremendous effort by our team managing the many contractors involved has kept this project on track and importantly in compliance with the many environmental regulations controls required up there. Certainly been no easy task for the team, but today, we are greater than 30% complete on the pipeline segments. And importantly, greater than 40% complete on the compressor station, so difficult winter conditions up there. But the team's really been working it hard, and importantly, as I mentioned, really paying attention to the permitting requirements that are on us up there.

We are targeting a July start-up to the mainline portion, with the greenfield compression likely taking a few months longer than that. Our LNG-related story continues, as well as the Gulf Connector has begun construction and we're targeting the first quarter of '19 for the in-service date for this 475 million a day addition to our Gulf Coast LNG delivery system. So we really have built out quite a delivery system along the Gulf Coast being able to serve all the growing LNG, and Gulf Connector will be the second big addition to that.

We also made the FERC certificate application on Gateway, a project that recently moved from the potential project list to full execution, and we continue to look at the potential to enhance Southeastern Trail. I'll remind everyone that we do have a binding shipper commitment that make a very attractive project for us on a standalone basis. But we are hoping to combine this with other customer needs to make another very significant, large scale and strategic expansion on Transco that would be right on the hills of the Atlantic Sunrise expansion.

Turning to the West. You may remember we spoke about the Chain Lake expansion in Wyoming during our third quarter call. Today, I'm pleased to update that we placed an additional Chain Lake expansion project into service in January, and as we continue to add volumes on our Wamsutter system in Wyoming. So all in all, a great quarter with significant complements -- accomplishments across a variety of fronts.

And with that, let's move on to Slide 5. I'm not going to spend too long on this slide, but it's an important and notable wrap-up reference regarding our 2017 performance versus guidance. All good news here with beats on all our key performance metrics and great progress on our leverage metrics as well. We continue to deliver, not only on our operational metrics, but on our financial objectives as well.

One thing I'd like to note here relative to debt. You can see our actual net debt to adjusted EBITDA came in well below the guidance and on PZ came in about 3.5 and on WMB, at about 4.4, which you can see is well below what we were targeting. You need to add about 3/10 to 4/10 to the actual number when estimating the rating agency calculation. If you do that, this gets you up to about a 3.85 ratio on PZ, and about a 4.75 at WMB on a consolidated basis. So just to be clear on that, we're excited about that. And certainly, we achieved better than we were hoping to for the year. But I would just remind you that we will see that creep up a bit here in '18, as spending wraps up on Atlantic Sunrise ahead of the full cash flow coming on, and then we expect that to come right back down as those cash flows come on. So overall, really great news on the credit metrics and we're continuing to drive our -- strength in our balance sheet.

Now let's move on to Slide 6, and take a look at our 2018 financials. There will likely be some surprise at our adjusted EBITDA range, which has a midpoint of $4.55 billion. But as we'll see on the next slide, our year-to-year comparison on guidance has recently been hit by about a $150 million of unusual noncash items that are driven by how regulatory accounting practices treat the new lower taxes and new GAAP revenue recognition standards that were applied to some amortized cash flows. Neither of these items impacts actual cash we will receive from customers in 2018. But I want to stress that this really is driven by these accounting practices.

Our base businesses look set to deliver guidance of about $4.7 billion prior to these items, which is a $300 million increase or about 7% on an apples-to-apples basis. So what's this $150 million of noncash items about? Well, first of all, the new GAAP revenue recognition rules require us to spread out some of our deferred revenue for contracts that we've already received payment on over about 10 years longer than the old rules and that drops the 2018 adjusted EBITDA by about $120 million, and then we also saw about $30 million in 2018 tax reform impact. Most of that comes onto Northwest Pipeline via regulatory accounting charges due to the tax reform even though the revenues we received from our customers won't change during this current rate cycle.

Again, we'll look at the bridge on the next slide. Moving to DCF, we have a range of 2.9 billion to 3.2 billion and the midpoint of the range represents an 8% growth over 2017. Our dividend and distribution growth rates related cash coverage and leverage metrics are all consistent with the guidance we provided this time last year. And now a year later out, we believe these growth rates will continue as we look out over the next 2 years. You will also note more specificity on the timing of growth through the year. At WPZ, we expect to increase distributions each quarter. So those will be quarterly raises. While at WMB, we expect to raise the dividend on just an annual basis, so once each year. So to be clear on that front, we'll be recommending a 13% dividend increase to be paid in March to the WMB Board here in the near future with the same dividend level being recommended for June, September and December, resulting in this -- sorry, the 13% increase at WMB, which comes in slightly above the midpoint from our guided growth rate last year. We expect the WPZ raise to be right in the middle of the range of that 5% to 7% range that we talked about last year.

We expect to maintain strong coverage at both WPZ and WMB, and the leverage metrics will remain at healthy levels, although we do expect the levels, as I've just mentioned, to rise a little bit as we expand on Atlantic Sunrise here in the near term. Coverage at WMB of approximately $100 million per quarter will be used to continue paying down the WMB revolver here in the first part of the year. And we continue to evaluate the best use of that excess cash flow at WMB post the revolver paydown, which will come in the second half of the year.

So let's take a closer look at that build up for 2018 adjusted EBITDA now on Slide 7. First of all, I'll begin with the big pieces. By virtue of our sale of the Geismar olefins facility in July of '17, you can see the $72 million step down there. That's just the EBITDA that was associated with those -- with that business. We expect a solid $300 million increase from our continuing businesses, with significant growth driven by Transco's expansion projects, partially offset by the loss of the Hadrian volumes on Discovery. We also expect strong growth in volumes and EBITDA out of our Northeast G&P business. Susquehanna supply hub is poised to make significant contributions, as expansion work currently underway will wrap up in the first quarter. The in-service of Atlantic Sunrise will lead to significant volume growth at both Susquehanna and Bradford County systems. But we are not counting on this until the later part of 2018, and recently executed contracts combined with new business we are currently finalizing will contribute to a very strong Ohio River supply hub growth.

The continued growth in our business and asset integrity work is waiting to modestly higher operating expenses in 2018. As you can see and then -- so wrapping that up, $300 million of adjusted EBITDA, which is approximately a 7% growth rate year-over-year when comparing results from the continuing businesses leads us to about a $4.7 billion EBIT -- what would be EBITDA before the impacts of these noncash new GAAP revenue recognition and tax reform impacts.

As I discussed earlier, the key impact of the new accounting standard was to spread out the recognition of the prepayments we received in 2016 associated with Barnett and Mid-Con contract restructuring. If you recall, those were on gathering contracts that we had with Chesapeake that now primarily are Total contracts, and reducing revenue recognized in '18 and '19, but increasing revenue recognized beyond '19 versus what we've expected on the old accounting standard. If you'll recall, it really was just driven by the fact that the period of the MDC was the period that we were amortizing that period over to the new accounting standards require us to smooth that out over the entire life of the contract, not just the period that had the MDC impact. The impact on 2018 is about $120 million, less revenue being recognized under the current standard than we would have recognized operating under the old standard.

We want to get in the habit of providing multiyear guidance. However, we do expect an even stronger level of growth in '19, particularly in Northeast G&P, and of course, on Transco. Given the timing around Atlantic Sunrise and the significance of that project, as well as other projects we brought on in '17 and '18, we thought it will be helpful to give you at least a glimpse here into what we expect coming off of Transco into '19.

So let's move on to Slide 8, and take a closer look at how Transco's adjusted EBITDA is growing over the next couple of years. So here, as we dive deeper into what is going on with Transco, it's clear growth and Transco will be driven by negotiated rate expansion projects, and there is strong growth coming in the future.

Let's begin with the impact of a full year revenue from the 2017 Big 5 projects. Note that in '17, we only had a $140 million partial year impact of the Big 5 projects that were placed in service during the year. And in '18, we'll see an increment -- on top of that $140 million, we'll see an incremental $110 million.

In 2017, we did have a significant step up in expenses primarily due to necessary pipeline integrity and maintenance programs. We placed a high priority on safe operations and on proper maintenance, and the cost of which you see coming through in our results in 2017. In 2018, you can see the full $250 million impact of the Big 5 when you add the $140 million partial year and $110 million in -- sorry, that was in '19. And you also begin to see the impacts of Atlantic Sunrise in Garden State here in '18 with a partial year contribution of $140 million after going into service in 2018. We also expect a big increase in Transco during 2019. So as you can see here, these are some of the drivers. First of all, the effect of a full year revenue from Atlantic Sunrise is captured here as you see full year impact of $425 million in EBITDA, resulting from a $285 million increase in '19 on top of the $140 million contribution in '18. And finally, as I mentioned earlier, Transco is also working on its next rate case. And I know there's a lot of high interest in this topic, particularly with the recently enacted tax reform law. So I wanted to talk you through what we think that process might look like as well.

First, I want everyone to understand that the negotiated rate contracts Transco has are not subject to change with this rate case. Tax reform will have no impact on these contracts. Those are firm fixed contracts, and both parties agree on a fixed rate on the front end for the term of those contracts. Most of our major expansions are covered by negotiated rate contracts. And in fact, by the time Atlantic Sunrise is in service, we expect Transco to be comprised of roughly 50% negotiated rate, and 50% cost of service base rates if the cost of service base rates that are subject to changes with each of Transco rate cases. Second, from a timing standpoint, we expect to make our initial rate filing in August, and we expect the revenue impact of new cost of service rates to be primarily a 2019 event.

And then third, I want to discuss the factors that affect the actual value of the new cost of service rate. Certainly, operating expenses are intended to be recovered in the cost of service rate. So for example, the increased expenses that we've been incurring on Transco from pipeline integrity and reliability improvements will be accounted for and recovered in our next round of cost of service rates. I would tell you that we continue to have a lot of work to be done in this to keep the system safe, and so you do see that cost continuing here for some time. Also, the maintenance capital spent on Transco goes directly into the rate base, and Transco will earn a return on that capital. So these items would work to push our cost of service rates up from where they stand today.

The Tax Reform Act has also generated lower corporate tax rate, which will also be a factor. There are 2 primary ways that the lower corporate tax rates will impact the pipelines rates. First is simply the lower costs that lower tax rates represent. The provision in our rates for current and future taxes will be lower, and now that's the corporate tax rate piece because that's kind of a forward-looking piece. The second impact is represented in the non-cap regulatory charge and related regulatory liability, which you saw when we discussed the fourth quarter results early in the call. This liability represents an estimate of the value that will be returned to shippers to account for their third portion of the income tax provisions that we've collected in the past on Transco's rates. This liability will be amortized off of Transco's books, and realized by cost of service shippers over an extended period of time, which could be as long as 20 years or even more.

So the ratemaking process on Transco for the cost of service contracts will likely be a negotiation that takes all of these factors into consideration, as we jointly determine the fair cost of service rates for our mass rate tariffs. So in summary, taking all of these items into account, along with other impacts to the cost of service model, Transco does still expect to file for an increased cost of service rate in our upcoming August 2018 rate filing.

So now moving on to Slide 9. As we've shown, we have impressive growth in the next couple of years, largely from long-term fully contracted and fixed-rate demand charges on a regulated pipeline and the expected pull-through under our existing gathering contracts. Beyond these near term growth drivers, our natural gas focused strategy and competitively positioned assets will likely capture even more growth in 2019 and beyond. And it's important to remember that Transco's fully contracted growth doesn't end with Atlantic Sunrise. And in fact, we have a committed backlog of 7 fully contracted projects that will go into service in 2019 and beyond, currently led by our largest of these, the Northeast Supply Enhancement project with commitments on that project from mostly from subsidiaries of National Grid. We've applied for the FERC certificate and the FERC is currently working on the environmental impact statement. We are targeting a late 2019 end service date for the project. But consistent with that practice, we include some additional time when forecasting revenue and EBITDA growth into our future business plans.

Beyond these fully committed projects, I want to update you on the large portfolio of potential interstate transmission opportunities we are pursuing. At our 2017 Analyst Day, we discussed approximately 20 projects, which we are pursuing at that time. Since that time, 3 of these 20 projects have moved out of this bucket, and moved from potential to customer committed. So we've made great progress on those projects. Rivervale South to market and the Gateway project moved into full execution, with FERC certificate application filed and the Southeastern Trail project now has binding customer commitments as I mentioned earlier. But new opportunities continue to emerge, and in fact, the potential project list has now been backfilled, and now stands at over 20 projects.

Moving to the Northeast. Pipeline infrastructure buildout will continue to unleash the power of the gas reserves in the Marcellus and the Utica. Based on our customer commitments and new activity, we now expect to expand our Ohio Valley Midstream processing capacity, which I'll remind you includes the Fort Beeler processing facility or complex as well as the Oak Grove complex. And we expect that combined capacity to increase by 400 million a day which will take us up to over 1.1 Bcf a day on that processing complex.

We also have discussions underway for a 6th major expansion of the Susquehanna supply hub, and in addition, we expect to complete the 5th expansion this quarter. So a lot of that's already online but we do have one remaining compressor station and a few loops we're putting online there. But really impressive how the Susquehanna supply hub and our work with both Cabot and Southwestern continues to expand our volumes up here.

In the deepwater Gulf of Mexico, we also are seeing great growth opportunities especially in 2020 and beyond. First of all, modifications to our Eastern Gulf assets to serve the new dedicated volumes from Shell's major Norphlet Play are under construction, and so we're well underway with that. And just to remind you, we've been installing a lot of those facilities, and Shell has been reimbursing us for those, and so we're really excited about seeing the impact of that will come on likely in 2020.

We are also very excited about our recent announcements from Shell on their Whale prospect and Chevron on their Ballymore prospect. Here, a few weeks, both these major prospects got announced, and just to kind of pin that down a little closer for you. The well prospect is within 15 miles of our Perdido oil and gas export pipeline, which come up on to Shell's Perdido facility and the Ballymore prospect is within 3 miles of Chevron's Blind Faith platform, where our Mountaineer oil pipeline and our Canyon Chief gas pipeline already served Chevron in these areas. So we do expect both of these major discoveries to drive significant free cash flows increases in 2020 and beyond, and finds such as Ballymore and well are clear indications that deepwater developments remain highly commercial, and Williams is in the absolute right spots in both the Eastern and the Western Gulf to benefit.

And drilling activity in Wyoming is going to continue to drive growth in our gathering and processing volumes in both the Wamsutter and the Niobrara field. In fact, right on the hills of the 2 Chain Lake expansions I mentioned earlier have now come to another expansion opportunity in the Wamsutter for an additional customer in this emerging play. So we continue to see a lot of activity going on out here in the Wamsutter field.

We also continued to see volume growth in the Eagle Ford and Haynesville, and this activity demonstrates the value of our strategy to be in the right spots and the best basin and to be a large-scale competitive player in whatever basins we're in. We see very attractive long-run return on capital from our Western gathering and processing footprint, and that return on investment capital -- invested capital will be extended by the latest round of this customer activity.

For now, we'll wrap it up here. Williams is committed to executing the plans that we've laid for our shareholders and customers, and to expanding our business in a manner that generates sustainable shareholder value. The result of strong execution in 2017 included generating healthy cash coverage that supports investments in our attractive portfolio of growth projects, while significantly strengthening our balance sheet. Williams realized a $3.3 billion reduction in consolidated net debt during the year. And through disciplined capital investing, we drove an important improvement in our return on capital employed, which has become really a key focus, not just from the management team, but obviously, that was driven by the board. And I would tell you that that's become front and center in our decisions as we look at our business.

And as we do look ahead to our plans to expand the business, I want to reiterate that Williams has achieved full self-funding. We do not need to issue any public equity at WMB or at PZ, and to fund our state of forecasted capital project through our pool planning horizon. We're able to do this, while maintaining a strong balance sheet and leverage metrics and healthy coverage of both WPZ distribution and WMB dividend.

WMB shareholders are now positioned to benefit from a $1.9 billion reduction in deferred tax liabilities, which will manifest itself through an extended period of cash tax deferral. Williams does not expect to be a cash federal income tax payer through at least 2021. And this could be potentially longer, of course, depending on our future capital spending opportunities. And we'll experience much lower taxes being paid when that deferral period does ultimately end. So we're excited about where we are with the company today. We're excited about where we're going. We think we are extremely well positioned financially. We've got the operating capabilities that we need. And strategically, we think we're positioned better than anybody in this space when it comes to taking advantage of these low cost natural gas reserves that continue to expand and grow demand in our both U.S. and international markets.

So I thank you for your time today. And with that, I'll turn it over to the operator for questions.

(Operator Instructions) And we'll take our first question from Jeremy Tonet of JPMorgan.

I wanted to start off with Northeast gathering and processing there, and the O&M had stepped up a bit quarter-over-quarter there. I'm just wondering if you could dive in a bit more on some of the drivers there. And also just expanding on the segment in general, if you could just refresh us as far as activity rig count in your area, and kind of what gives you the confidence as far as the growth into 2018?

This is Micheal Dunn. I'll take that question. In regard to the expenses in the Northeast, I will tell you, from an enterprise perspective, let's talk about that first. We look at improvements in our operating margin across the entire enterprise and each one of our operating areas. And we drill that down to the franchise level within each one of those operating areas. So we have set goals for the organization to improve those targets on our operating margin. In the Northeast, specifically, obviously, we're seeing significant growth up there. We're adding a number of facilities, whether it be compression or pipeline facilities that includes additional employees, but an additional operating costs that come along with that, whether they be electric power or our facilities, as well as the costs that go along with that. So we're seeing really strong growth in our revenues up there, and correspondingly, with that growth, we're seeing increase in our cost. Specifically, in the Northeast, we saw the new compression facility that came online. Our new employees, as I mentioned, the additional electric cost. But we also had emerging work in West Virginia dealing with longwall coal mines that are underground coal mines that we actually have to go out and mitigate the pipelines that are above those coal mines, so that we don't have any operational issues. So we target those, and we typically know where those are going to occur, and we work with the coal mining companies to mitigate that, but that does increase our expense there, and also avoidance of impacts from land movement in primarily West Virginia. We did have some emergent overhauls at our Fort Beeler facility as well that were unanticipated that increased our costs there. We did have a pension lump sum settlement too that obviously is adjusted out of our GAAP earnings, but -- GAAP numbers. But those obviously affected us there. That actually lowers our costs, going forward, in the future, but had a one-time impact on our business. So I would say in the Northeast, specifically, we are seeing a lot of growth, and it is driving costs higher, and we do have expansions underway, not only in the Susquehanna supply hub. Bradford costs are increasing. But in the Ohio River Supply Hub, with our Oak Grove expansion that we're working on there as we speak. We'll see cost increasing there as those facilities come online as well next year. So growth is driving costs higher. But certainly, we're watching very closely the operating margin associated with each one of those franchises. And we had set goals established for our teams to meet or beat their objectives there. When it comes to rig counts, we are seeing a lot of improvement there. In many of these areas, the producers are anticipating the online of Atlantic Sunrise. And correspondingly, we're seeing a lot of drilling activity in anticipation of Atlantic Sunrise coming on. But the additional takeaway capacity that's been generated by third parties in the Marcellus are -- we also are benefiting from that as well. So we're seeing a lot of production growth that's anticipated, especially in some of the wet plays that we're associated with, and that's driving lot of additional business for us, as I indicated in our Oak Grove expansion, as a great example of that.

Great. And maybe just touching on Southwestern to build on there, if you could just update there as far as how the ramp progress during the quarter and how you see that kind of going into '18.

Maybe just -- this is Alan. I'll just add a little bit there. First of all, in the Southwest Marcellus area, Southwestern has been very active there. And just to remind you, we signed a contract with them last year. And the way that contract works, they basically inform us ahead of time when they are bringing on -- when they intend to bring on new volumes. And as they do that, our capacity that we make available for them on the processing expands and their minimum volume commitments expand to stand behind those investments that we make. And we have seen them increasing those requests for service which drives that up, and so a lot going on there. I would tell you that there's quite a bit of activity right now going on connecting a lot of their pads. So I think they're -- they've been very successful out there, and we are thrilled to have them as a customer out there and they continue to improve. So feeling good about that relationship. We also, as you know, have expanded our relationship with EQT in the Ohio River Valley Midstream area, and they are being very active in driving some of the growth that we're seeing there at Ohio Valley Midstream as well. So finally seeing some real pull-through as the acreage out there has gotten into the right hands. And it's great acreage, and was held by various counter-parties. But the consolidation we're seeing out here in and around our acreage is really starting to rival a lot of activity and growth.

Got you. Great. And just last one, Discovery. I was wondering if you could provide a bit more color there and kind of your outlook and kind of ability to kind of redeploy or get more business there.

Yes, sure. So just to kind of remind people there, the Hadrian field, which was a large gas only field that came across Anadarko's Lucius platform, but it was an Exxon-operated field. Hadrian was-- 2 very large wells that were producing, I think, they got up to almost 400 million a day of production off those 2 wells of dry gas. That came across that platform. I'm not going to get into Exxon business there, but we've seen that production decline off dramatically, and we don't, right now, expect that production to come back online here for 2018. And so they'll have to decide what they're going to do with those reserves. But right now, we don't expect that to come back on anytime soon. That was about roughly, I think, in terms of impact to our expected '18 numbers, it was about $95 million in terms of reduction on what would have -- or I should say definitely in terms of what we saw in '17. It was a reduction from '17 to '18 by that amount. That's net to our interest. We own 60% of the Discovery system. Lots of other prospects out there in the area. And frankly, we were running completely full on that system, both on the processing side and on the Keathley Canyon connector, which is that line that goes up to the Lucius platform. But there are some very large RFPs that we're bidding on right now. So we don't expect anything to -- of that kind of significant to backfill that here in 2018. But there's a tremendous amount of prospects there in the Keathley Canyon area that were -- beat the gas takeaway solution for that area. So we would expect to win that business. So short term, negative. Long term, Discovery, as always, is positioned at a great spot.

And our next question comes from Jean Ann Salisbury from Bernstein.

I think you've said before that after Atlantic Sunrise comes online, Chesapeake will be down to 10% of your EBITDA. I wanted to make sure that that's about right? And as a follow-up, would you be willing to comment on your next 1 or 2 largest customers? Are they E&Ps or utilities, and kind of roughly, what share of EBITDA they are?

Well, let's see. First of all, on the Chesapeake front, yes, I think your 10% number is fairly accurate. As we move forward here, I would say, obviously, that's dependent on asset sales that Chesapeake continues to execute on. And so with additional asset sales, that might drop lower. In terms of our largest customers, I would tell you, it's quite a mix there. Certainly, Cabot has been running up fast on that list with all of the great business that we have within their Susquehanna Supply Hub and then -- and Atlantic Sunrise comes on. And then -- so I think that's really going to drive that. And as you look below that, you'll start to see a lot of the big utility customers that we have on the Transco system. So anyway, I think that's probably the right way to think about it. And obviously, Southwestern is emerging, but not anywhere near yet where we see Cabot as an E&P customer.

Okay. That's really helpful.

I'll take that.

That's really helpful. And then just as a quick follow-up, a number of the Marcellus E&Ps are now discussing living within cash flow at least over the next couple of years, I guess. Has that impacted your growth outlook? Or is it fair to think that the Northeast Marcellus is somewhat immune from that just because it's so takeaway constrained?

Yes, I think, obviously, we stay very close to Cabot, and they are -- they've done a great job, have been very disciplined, and as you know, continue to build a lot of cash on their side. So I think they will just continue to generate more cash as new markets open up. So it's pretty remarkable for me to see what they've been able to do in such a very low-priced environment that they've been exposed to. And so I think they are capable of operating in very low-priced environment and continue to generate cash flow. So as for Cabot, I would say that. I think in terms of the moving down to the Bradford area, obviously, great reserves there as well, and that area is going to benefit from much better markets as well. And then finally, in the Southwest Marcellus area, obviously, these higher NGL prices that producers have been experiencing in that area are really driving cash flows for folks there. But I think right now, we're seeing an intense focus by the players that are really beginning to consolidate these basins. EQT is probably the biggest example of that. But their ability to generate returns on low price -- even low prices, I think, is going to continue to drive the kind of growth. Frankly, we're better off as a gatherer. We're better off if that growth doesn't come in huge spikes, but comes in a steady growth pattern because it means less capital investment per free cash flow for us. So we're pretty pleased with the current rate of growth that we are seeing and it's right in line with what we laid out last year in our Analyst Day, as we look back pro forma that we rolled out at the Analyst Day last year. We're pretty well staying right in line with that, and that's going to drive a lot of value for us if it continues on that trajectory.

And our next question comes from Christine Cho of Barclays.

I want to start off in the West. The volumes were good. Can you just remind us if the Haynesville contracts are higher margin than the other G&P areas in this section?

No. There -- I mean, the rates there, as you'll recall, we renegotiated those rates several years ago, and we exchanged a lower rate for drilling obligations from Chesapeake, and we combined those 2 systems out there. So I would say our rates out there today are in line with the market. In terms of the margin, the operating margin that we have out there, it's probably in line. I think the benefit we have out there right now, Christine, is that we had quite a bit of capacity already built. So if you recall, we did a little expansion back in August of last year. And -- but overall, we've got the capacity sitting there, and these pads are pretty well built out. So we're not having to spend a lot of well connect capital, and our operating costs continue to be pretty low for the area just because the system's already built out. And so that's the kind of advantage you have when a system comes back, and you've already got the capacity built out for them. So I think that's that margin that you're seeing.

I actually didn't mean relative to like market. I meant relative to the other areas in the West segment. So are the Haynesville rates higher than like your Niobrara, your Rockies, et cetera?

No, they are not. But again, it's very dependent on the total services that we are offering. And so what I was getting at there was that we've already had these operating systems up and running. And once they're a little more mature, we're able to really put pressure on our costs as opposed to when we're in a growing mode and we're having to add people and quickly bring volumes up. So I would just say, because the Haynesville has been operating for quite some time, our unit operating cost there are pretty mature. So if you wanted to get down to operating margin percentage there, it's probably pretty good on that basis.

Okay. And then I wanted to go to your Slide 8 in the presentation. The 425 million full year contribution from Atlantic Sunrise and Garden State, I just wanted to clarify if these are growth or net numbers to you, as I think, Atlantic Sunrise is consolidated in your financials, but the noncontrolling interest line is below the adjusted EBITDA.

Yes. No, you are correct. That is the gross number.

Okay, and do you have (inaudible)?

That is what goes in the EBITDA, and then hopefully, a minority interest deduction number.

Okay. And then lastly, WPX sold their San Juan acreage, and just wanted to see what kind of impact do you expect to see from that, if any? And to confirm that the contracts will transfer over to the new owners?

Yes, we -- first of all, we haven't seen the contract shift yet. So obviously, we'll take a look at that, as we do, in a situation like that. We've been able -- always able to work with our customers to deal with credit issues, which obviously is the primary issue in any kind of exchange like that. But I would -- so too early to tell you on that. We haven't included that. I would say that we're continuing to see the acreage fall into the right hands. And it's very much a positive for us when we see acreage shifting around like this, because as you know, WPX has a lot of high return investment opportunity in the Permian that is going to keep them busy for a long time, and so moving this over to somebody who will bring the cost of capital to it -- that it needs in the Mancos oil play there. It's a positive thing, and really seeing that throughout the West. So we just continue to see properties falling into the right hands, and we think that's a real positive for us.

And from Goldman Sachs, we turn next to Ted Durbin.

On the Transco rate case, I wonder if you can quantify what kind of rate increase you might be looking for? Are we talking in sort of the double digits in percentage terms? Or maybe said another way, how much do you think you're under earning on your cost of service rates right now at Transco?

Yes, Ted, I will just tell you that, that is -- will be determined when we get done with the test period or base period, and so that -- we're forming those rates. And when we get done, I think that ends here in May, I think, and that will form the basis for that rate in August. But I would tell you, the numbers on Transco are big, and it takes a lot of (inaudible) and direction in those rates very much. So don't expect any major shifts in that rate one way or the other.

Okay, that makes sense. And then as we think about the O&M increases you've had in the Atlantic-Gulf segment, you talked about Transco and the higher maintenance capital we've had. Should we think about what we're looking at in 2018 as a good run rate? Or should we see a step up or step down as we look ahead into 2019? You had your maintenance capital numbers stepped up decently well here in the guidance versus where you've run the last couple of years. Just talk about run rate operating cost, particularly around Transco, please.

Yes, Ted, thanks for the question. First of all, you could draw the conclusion that -- without seeing the details, you could draw the conclusion that our expansions are really driving a lot of that costs, and that's just not the case really. The expansion -- the cost is being increased as we go through the process of doing things that you might consider that look -- to some people would look like maintenance capital, but by the details of the work, are not maintenance capital. So for instance, doing hydro testing on pipeline and doing repairs, all of that winds up in expense. We have a lot of that to do on the Transco system. And certainly, because we operate in such high populate -- highly populated areas, we are going to spend the money to make sure our pipes are safe. And so that kind of cost, even though some might consider that maintenance of the system is really what's been driving our costs up here recently, and we've got a lot more work to do on that front. So those costs will continue for quite some time as we do that. Now the thing that's difficult about that is predicting what that cost is actually going to be because when you hydro test a line, if you do see problems, you're having to forecast the rate of repair required, if you will, when you do either the internal inspection testing or the hydro testing, either one. You'd have to estimate what your rate of repair is, and so that just becomes an estimate. And until you actually run the testing, you really don't know what your repair requirements are going to be. So that becomes a little bit difficult to predict, much more difficult than just ongoing operating expenses of keeping a compressor station running or keeping the right-of-ways maintained and the measurement systems maintained on the pipeline. So hopefully, that helps you understand. But I think bottom line is we've got high cost that are related to bringing the -- making sure we've maintained the system adequately, and that will continue for some time here.

Okay, that's great. And then last one for me just on CapEx guidance, $2.7 billion total, $1.7 billion at Transco. Can you just bridge us what goes into that $1 billion difference? Is it more in the Northeast and some of the OVM spending you talked about at the deepwater? Kind of a little more color on where that $1 billion is coming out of?

Yes, sure. First of all, as I mentioned, like the Norphlet project we're doing for Shell on the Deepwater, that's included in capital. But if you really got down to seeing the sources and uses, you'd see that being reimbursed even though we count that as capital. So some of that is in -- is reimbursed capital. It would show up as capital spending, but in fact, it gets reimbursed. And so that's about maybe 20% or so. That's 15% maybe. And then in the Northeast, a lot of growth going on again with the 6th expansion that I talked about in the Northeast, as well as the build-out of the Ohio expanding the processing capacity in the Ohio Valley Midstream area. And then out West, the Wamsutter area is the primary driver for growth out West as we continue to expand those systems. And I would tell you that probably the next area that we'll be looking to need to expand are probably the Niobrara with the growth that's going on there. So that probably will wind up being more of a '19 issue perhaps based on spending on that. So that's really driving most of it. It's actually in all 3 areas. The largest of those right now though is the Northeast in both the Susquehanna County area, as well as Ohio Valley Midstream area.

Next is Shneur Gershuni from UBS.

Maybe we can start off with the balance sheet and expectations on return of capital going forward. If I recall, when you did the restructuring early last year, you're sort of seeing that there was a goal to reduce leverage by about $5 billion. You did the equity issuances. You've had some asset sales and the EBITDA seems to be recovering and so forth. I was wondering how far away we are until the agencies would view the consolidated entity as IG? And then what your expectations are for returning cash flow with respect to WMB getting -- those 2 paying off at your revolver in the second half of this year?

Yes. I'll take the last part of that question, and I'll let John Chandler take the first part in terms of the balance sheet piece of that and the rating agencies. On the return of cash flow, I will just say, lots of different opportunities for WMB. We are excited about adding value to our shareholders with that excess cash flow. But as we've said previously, we're going to be looking for the best opportunity, and so that can come in a lot of different forms, as you know, not a singular debate to Williams. But I would say one of the areas that is also attractive is WMB making singular investments in new project opportunities, as WMB is an opportunity as the opportunity of -- slate for Williams continues to grow. That's not everything, obviously, because we don't want to make things so convoluted between what's owned by MB and PZ. But we will certainly look for that given how many really highly attractive projects we've got out there. And then of course, the continued dividend rate, obviously, is placed to go with incremental cash. So lots of opportunities on that front, and I would just tell you, we'll see what the market looks like 6 months from now in terms of when we're up against that, so stay tuned. But I'll tell you, we're excited about using that capital to drive additional value for WMB shareholders. And John, if you'll take maybe the question on the balance sheet?

Yes, sure. As we exited 2017, WMB had about $270 million outstanding on its revolver, and we're generating around $100 million of excess cash flow every quarter at WMB after it makes its dividend. So we'll continue to pay that revolver down, and that obviously puts us in the third quarter, fourth quarter when the revolver is gone, which will further bring our leverage down. But again, as Alan pointed out earlier in the call, with the spending on Atlantic Sunrise and the various other projects, our leveraged will pick up somewhat as we get to the end of 2018. And then once we get the full benefit of Atlantic Sunrise, it will come back down again. And so as I think about investment grade, and as a consolidated entity with the $4 billion in debt that's up at WMB, I think we need -- and when we talk about investment grade, when we say investment grade, we really talk about mid-level investment-grade, not a BBB- but a solid BBB ratio. We think we need to be in the probably 4.5 to 4.75x ZIP code of debt-to-EBITDA and it's depending on when the rating agencies give us kind of full credit for Atlantic Sunrise. But I think in the early part of '19, we can make a pretty strong argument in that -- about that.

Great. And as a follow-up question, you were talking about the Northeast earlier in response to a question, talking about how Cabot is able to operate in the low cost environment and there were some other questions about how bottlenecked the Northeast is. But at the same time, Mariner East 2 is expected to come online. Rover is expected to come online and so forth. In your conversations with E&P companies, how much do the IRRs for them to drill change as a result of these projects coming online, and does that -- once that hits, does that accelerate the opportunity for you to achieve what you outlined at the Investor Day about potentially investing $1 billion of capital in the Northeast at a 2.5x EBITDA multiple?

Yes, great question. I would just say, Shneur, that the one thing that's a bit complex around that, obviously, is who has long-haul capacity that they hold or don't hold. And so I think that -- will tend to drive, whether somebody is being very opportunistic and very short term, and just drilling when the pricing is there. Obviously, they can turn these areas when the infrastructure is already in place. They can -- and they've got a pad sitting there. They can turn incremental production on very quickly when the pricing opportunity exposes itself. I think we're going to see more of that as the capacity gets built out. But I do think it's very dependent on if you've got long-haul capacity that you are constantly filling or you have a gas purchase contract for a good price that you can depend on. You can be more of an ongoing and less reactive mode if you're a producer in that situation versus if you're one that's just sitting, waiting for a price peak and hitting that. I think what we are seeing through the consolidation in the basin is more of the former example. I think previously, we had a lot of the latter example. And the big consolidators in the basin are making long-term commitments to either NGL takeaway or gas takeaway, as you mentioned, and that is going to position them for long-term drilling, and is going to make their variable price point very different than somebody that doesn't have that take away capacity. And so I think we are certainly continuing to see expansion going. I think people are getting better and better at getting their costs down on the reserves. And so I think that's pretty promising for the Northeast in terms of volume. But I also think though there has been a pretty strong delineation because people have got such a strong portfolio of opportunity that it's going to be a while before people get to the lesser acreage. And by that, I mean the lower return acreage. I think it's going to be a while before people get to that because there's such a great inventory of the very strong acreage in both Susquehanna and Bradford County in the Northeast, and then of course, in West Virginia and for Southwest Pennsylvania for the rich Marcellus. So look, I would say, feeling pretty optimistic. But I do think to answer your question, it's very dependent on what the producers' long haul takeaway or their gas purchase contracts are out of the area as to how steady their drilling is going to be.

Final question, with respect to the Gulf of Mexico, and I understand there's the Discovery dispute and so forth. But it seems like producers, and I believe you mentioned Shell, seem to be adding capital into the Gulf of Mexico, talking about tiebacks profitable at $40 oil. Do you see this as an emerging opportunity for Williams going forward? Just kind of wondering if it's a one-off or if it's something that we should be thinking about across the Gulf of Mexico.

Yes, I would tell you, we happen to be in the right spots. And so that's the business. And we've got on top of the prospects that we talked about today, there's a lot of other opportunities that are emerging and quite a few large RFPs that we are responding to for big infrastructure development in the area. So I would say we have seen a resurgence. I don't think that it ever went -- quite went away the way people thought it did in terms of the opportunity because folks like Shell don't just turn on a dime on these kind of things. They've got a long-term commitment to the area, and they've been sitting on that well prospect for quite some time with the -- but they've got to make sure there's room for the infrastructure, both on their platform and in our pipeline to get that gas and oil out of there, and so that's kind of what you're seeing manage. I think people are trying to lessen their big capital commitments and trying to utilize existing infrastructure as much as possible, and I think that's really the shift that we've seen. And I think you'll continue to see that. Because if you can use an existing platform, and you're not having to put billions of dollars in new infrastructure in, you can be pretty responsive to oil and gas prices. And I think that's what we'll continue to see up in this play.

And our next question comes from Colton Bean of Tudor, Pickering, Holt & Company.

I just wanted to follow-up on the conversation around Northeast producers. So I agree in the consideration of pipeline capacity. But it seems like at least in the near term, there's been some consideration that producers may pull off volumes from local hubs relative to actually adding new production over to '18 and maybe into 2019. So just wanted to get a sense of how you guys were thinking about that as you formulate your forecast for the Northeast?

Yes. Well, I would say that we look at what requests come in from our producers to actually formulate our forecast, and as I mentioned earlier in the call, a lot of those come with obligations. So when a producer says that they want to increase their volumes or their capacity on our system, that comes with an obligation that stands behind that. So we -- obviously, they've given that good thought, and before they make those kind of commitments. So -- but that's basically what we generate our forecast off of. I would say we have very little speculative drilling in -- built into our forecast and is really more driven off of that. So -- but I would, say as we look at in '19, first, '18 is strong with about, I think about a 13% increase from the fourth quarter, fourth quarter, so exit rate to exit rate. And so that's very identified right now in terms of where that volume is coming from. And as we look into '19, we're seeing similar pull-through. But again, so many of our contracts are either cost of service, which requires long-term planning or minimum volume commitment that -- contracts that -- that's what really what's driving our forecast.

Okay, helpful. And then on -- just to circle back to the West segment, so it looks like you're up about $250 million in the gathering piece. So you mentioned the Haynesville, but then 8 of the other 10, or I guess 8 of the other 9 were also up. Can you just frame what the magnitude was? Was there any meaningful contributors there or predominantly Haynesville?

Haynesville was the biggest. I think behind that, probably on a percentage basis (inaudible).

On a percentage basis, we saw a pretty significant increase in the Niobrara. Although it's a smaller number. It's a big increase we saw. As we mentioned, the Haynesville and even some improvement in the Anadarko. So across the board, we saw pretty good improvement across all of those. Eagle Ford was up almost double digits there as well. So...

Yes. I think on order of magnitude, I think Haynesville and Eagle Ford were the 2 biggest drivers. But on a percentage basis, Niobrara is pretty strong. And I would tell you, given the current activity, we expect that to continue to be pretty strong percentage driver even on an absolute basis. That doesn't have that much impact.

Got it, okay. And just the final question here on maintenance. So relatively light versus 2017 guide. Is that tied at all to your conversation around the O&M spend? Did some of that transition from what you would consider maintenance CapEx to the operating expense line or just came in lower-than-expected?

I would say -- this Micheal Dunn again. I'd say, it came in lower-than-expected across the board, really across all of our franchises. We anticipated some work that actually would likely shift in to 2018. From the appearance of a lot of it was just -- a lot of that work was in process, but just didn't get completed in the fourth quarter. So we are seeing some of that shift in 2018, which is not -- that's pretty typical, I would say, as to what we see, where we do have a shift at the end of the year. And some of that work that we don't just get completed and it just ended into the future year. But we really thought across all of our franchises, where we had work that was anticipated, to be completed and we just didn't get it finished.

Okay, so with 2018 being flat versus the 2017 guide, implications that 2018 would have actually been down. Would some of that flip to the -- to this year?

No, I would not characterize it that way. In fact, we are seeing 2018 slightly ahead of where we had anticipated 2017 to come out. We're seeing a lot of work, as we indicated earlier in our Transco system that -- not only on the expense side, but on the maintenance CapEx as well for integrity and reliability projects.

So yes, to be clear, we are expecting an increase in maintenance capital from '17 to '18.

But is that effectively flat, $500 million, both years?

We came in below that $500 million in '17. So I think we came in at $440 million in '17.

That's correct.

That's right.

So I think, one thing, when you look to our guidance for 2018, we widened our distributable cash flow guidance, in part, because of trying to really fine-tune around maintenance capital spending. I think the last couple of years, if you look at our performance versus our guidance, we've come in below the guidance, and it's just a matter of how much work you can get done, and typically, we don't know that til we get towards the end of the year. So we widened the guidance a little bit to reflect that.

And from Citi, our next call comes from Eric Genco.

I was just hoping to drill in maybe a little bit on the excess coverage at WMB and the shareholder return question. Is it fair to characterize and say, "If you've got 1.36 excess coverage there that your first priority after you're done with the leverage pay down is -- would be projects that you needed to avoid public equity issuance of other entity? But then is it basically, as people are sort of anticipating the potential for a consolidation of the 2 entities, is it just as a matter of looking at WMB's NAV versus its ownership of PZ? And if that is at a discount, should we assume that WMB buybacks move up the pecking order in terms of what you would like to do with that capital?

Yes, all of that. There's obviously a lot of things to consider there. But as you know, one of the tax reform course pushes out the date by which we would be a cash taxpayer at WMB, which is obviously one of the benefits of getting that tax first. And secondly, ultimately, the tax rate that we're paying just got lowered as well. So I would just say that driver is somewhat less than as a result of the tax reform bill as we look out there. So John?

No, I think, obviously, and Alan alluded to this earlier, when we get to that point, we will be making a relative return decision. And if WMB appears undervalued, maybe we buy back WMB shares. If WPZ seems undervalued, maybe we buyback WPZ shares or maybe we co-invest in projects. Generally, as it relates to the buy-in of the partnership, now that the tax reform is understood, once our leverage gets right, I think, generally, as it relates to that entity, we'll have to take a look at how the MLP space is doing in general. I think the MLP is a tool to raise capital over the long term. If that market was strong, I think we'd have to ask, do we want to make it go away or not? And if the space is kind of just trending sideways, like I mean, it's a little bit improved now, but it's generally trending sideways, then you have that stuff. Why leave it outstanding? So I think it's a bigger picture than just that. I think it's a question about the strength of the space when we get there.

Okay. And then shifting gears, I was just -- and this is a bigger picture type question. on Northeast. If constitution were to never happen in some of these other pipes that are there, how do we think about the multi-year outlook for Northeast G&P? Because for the longest time and even now, we're waiting for constitution to come on to basically debottleneck Susquehanna supply hub, and I believe Bradford to some extent. But if you don't get Constitution or some of these other things, are there other opportunities? Or do we sit back and say, the volume increase from, call it, 4Q '17 to 4Q '20 in those areas is pretty much limited to Atlantic Sunrise's capacity?

Yes, great question. First of all, I would just say, we have other projects ultimately. And of course, we have a project called Diamond East, which follows our Leidy route and the expansion of our Leidy route, a lot of recent interest in that project. So that expands capacity into Zone 6 in a pretty meaningful way as one alternative. And then additionally, ultimately, there, we have some expansion capability on Atlantic Sunrise. So I would just say, if the folks in the New England area want to continue to buy their gas from Russia, they can, and the folks in the south will benefit from that. So that looks like what's that's going to continue to be is lower cost gas supplies for the growing industries in the South, and so we'll see on Constitution. I think in the grand scheme of things, it's an important -- it's not that big in terms of total volume takeaway from the area. It is important, I think, in terms of determining if the Trump administration is going to be successful in pushing for infrastructure development, and so we remain very committed to that. But I would tell you, in the grand scheme of things and market takeaways, there's plenty of market going to the south. And we're very well positioned to be able to get that gas there through either expansion of Atlantic Sunrise or Diamond East, as I've just mentioned.

Our next question comes from Darren Horowitz of Raymond James.

Just a quick one for me. When you think about the EBITDA build up, not just for '18, but going into '19 as well and you think about it more on an EBITDA per Mcf basis, can you just help us understand how much of that buildup and progression is the Atlantic Sunrise volume contributions into the Susquehanna and Bradford systems in addition to Garden State versus maybe just more aggregate takeaway capacity, alleviating base pressure in the basin? And then into '19, how do we think about the construct of that EBITDA buildup versus what could be rising on in expenses again?

Darren, to make sure I heard that correctly, first of all, the last part of that on the buildup, the cost build up that you see there in '18 certainly would carry -- that cost increase would certainly carry into '19. But not a whole lot of incremental costs associated with bringing those projects online. So as I mentioned earlier, it's more going to be driven by the maintenance work. And that step up that you see in the prior year will carry in to the '19 period as well. So I think that answers that part. If you try again on -- I didn't quite understand the basis differential question.

Well, I'm just trying to figure out, like if you look at the gathering capacity in Northeast Pennsylvania, it's probably pushing at this point for you guys, 6 Bcf a day. So I'm trying to figure out, as you guys kind of progress on that EBITDA per Mcf ramp that was laid out at the Analyst Day, obviously, incremental takeaway capacity by you guys and your competitors out of the basin is going to alleviate basis pressure. Based on your footprint, you're going to get your natural market share with regard to a step up in volume based on just easy capacity utilization. So I'm trying to figure out how much of it is driven by the basis uplift and incremental volume across your assets versus what you guys are adding on a fully contracted basis such that the EBITDA per Mcf could shift a little bit?

Got it. Thank you. That's very helpful. Thank you. Yes, so I would say, first of all, we do think that there is a lot more growth out of the area than just, for instance, Atlantic Sunrise and/or potentially Diamond East. We think, obviously, if you look at Cabot's slides and all the different market and gas purchase contracts that they've done with power plants in the area, they've got a nice step up coming from that, and so I would say they've been pretty, pretty smart on that. But I also would remind people that as the big takeaway projects come out of the southwest part of the Marcellus or Mountain Valley and Atlantic Coast, as those come online and get attached to growing markets there, that will pull gas off of systems like -- that serve the Northeast today that are in -- serving that local market. So even the Northeast PA will gain some benefit from that takeaway capacity to the southwest because you'll just see volumes start to be supplied from the Northeast rather than the southwest on a local -- in both power plant basis and local use. But in terms of our EBITDA margin and what we're expecting in pull up there, most of it is just coming or we haven't fixed the contract, and the EBITDA margin is just coming from our cost remaining relatively flat, plus a mix of a higher portion of our volume coming from places like Ohio Valley Midstream, where we have a much higher margin per Mcf basis. And so those are the 2 main drivers for us. But as I mentioned earlier, in terms of our volume forecast, it's pretty well driven by detailed plans that we have with. In fact, it is driven by detailed plans that we have with our producing customers right now, as we build out those systems and their obligations stand behind that. So I would say, at least for the next couple of years, we have a very good read on what those -- what we expect those volumes to do. We have won some new business, and are winning some new business in the southwest area that will increase our processing volumes in the Southwest that would have been over and above our earlier forecast. But for the most part, our forecasts are just driven by our existing gathering contracts and the plans that we have with those producers today. And that by itself is driving that EBITDA uplift on -- EBITDA margin uplift, if you will, that we spoke about in the last Analyst Day.

And we'll go next to Chris Sighinolfi of Jefferies.

This is Corey, phoning up for Chris. So much answer -- you've answered a lot of questions. Just 2 really quick ones for me. The first one is I just want to make sure we heard the Transco timeline correctly. So on that Slide 8, that $140 million walk from '17 to '18, that assumes to July in-service of compressor and you said a few months after that would be the greenfield pipe portion that would start contributing?

Right. Yes, I could take a little bit more color on that. Right now, we're anticipating and targeting that our contractors are going to be mechanically complete on the pipeline portion in July and mechanical completion means just that. The contractors are finished with their work, and then commissioning begins with our teams. And with the compressor stations mechanically complete, the time between mechanical completion and in-service, when you can commission those compressor stations, takes a bit longer. There's just a lot more processes that have to go through on the compressor station to complete your commissioning activities, where it's lot of quicker on the pipeline systems. You're really just commissioning valves and meter stations on the pipeline, but much more complicated on the compressor station. So the compressor stations lag a few months there although their percentage completion right now is leapfrogging the pipeline. The process, the commissioning process, takes a bit longer with the compressor stations. So that's why you see a little bit of a lag there on the compressor stations beyond the pipelines being mechanically complete.

Okay. All right. That makes sense. And then there's -- so I'm assuming this was done on purpose. But there's no way you can bifurcate Atlantic Sunrise and Garden State for us, can you?

As far as a revenue impact, EBITDA impact contribution, yes.

Perhaps that EBITDA, that $140 million split, I don't know if you can for us.

Yes, I'd tell you what. Why don't you call our IR team and they can give you some detail. I think we have provided some information previously that will help you on that.

Okay. And then just last one from us is -- and I apologize if I missed this. But the cadence of the dividend and distribution growth in 2018, the quarterly for PZ; the annual for MB, was that new?

Well, we've talked about the increase, the new piece that we laid out today was saying that we were just going to go ahead and just do annual increases on WMB versus quarterly distribution increases. So that is new. We've always -- the percentage of annual increase is staying the same. But the annual versus quarterly distinction is new.

Got you. Okay. And just out of curiosity, the motivation for the difference there?

I would just say, first of all, I think the MLP space is used to the quarterly raise and the quarterly distributions. And I would say large, more utility like C-corps are more annual raises. And so we were just pretty well staying in line with what we see really ought to be more of the pure market for WMB, and so that's really the driver on it. (inaudible)

I apologize. This concludes our question-and-answer session. Mr. Armstrong at this time, I'd like to turn the conference back over to you for any additional or closing remarks.

Right. Thank you. Lots of great questions. Thank you, all. I appreciate all the attention to the business, really well positioned as we go forward here. I think the low gas prices that we're seeing, particularly in the forward market, are just evidence of the people's confidence in our ability to utilize and get low gas, low-priced gas out of the ground. We think that's a really positive thing for us, both on the LNG development in those markets, as well as the development on gas-fired generation, and I think we'll see some of that this summer. That demand starts to pick up as well. So really excited about how the fundamentals are supporting our business, and especially pleased with the continued improvement and executions on our projects by our teams all across The Williams system. So we thank you for your interest, and I look forward to talking to you soon. Thank you.

And this does conclude today's presentation. Thank you for your participation and you may now disconnect.