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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, everyone, and welcome to the Williams and Williams Partners Fourth Quarter 2017 Year-End Earnings Conference Call. Today's conference is being recorded.
At this time, for opening remarks and introductions, 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 a slide deck that our President and CEO, Alan Armstrong, will speak to you momentarily. Joining us today is our Chief Operating Officer, Michael Dunn; and our CFO, John Chandler.
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 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. 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, just because there are a lot of issues that we 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 2017. A lot of notable achievements. We safely, and in timely manner, delivered on Transco's Big 5 projects, which was Gulf Trace, Hillabee Phase 1, Dalton, New York Bay, and the Virginia Southside II. And we exceed 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 2017 despite the impact of Hurricanes Harvey, Irma, and Nate, and while executing crisply on $2.3 billion in asset sales. And if you go back to September 2016, 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 attractive 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're 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 as 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're going to take a brief look at the types of opportunities we see driving our growth into 2019 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 to slide 2 and review the fourth quarter. So, according to our GAAP results, which included some large onetime 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 2016. This large improvement was driven primarily by the re-measurement 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 non-cash charge at WPZ related to Tax Reform for Transco and Northwest Pipeline. I'll go further into the Tax Reform impact on the regulated pipelines 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 calculations by 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 rates 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've 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 segments.
And with that, let's move on to 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 2016 when you exclude the former NGL/Petchem businesses that we sold.
You can see in the graph where all three 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. And as you'll recall, we own both a rich gas gathering system and then we own a 62% interest in a non-operated interest in UEOM up there.
In the Northeast, we've consistently spoken of 2017 and 2018 as transitional years for Northeast volumes. During 2017, we started to see step changes in takeaway 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 the 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 two of the 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 debottlenecking 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 five major projects this year, which added over 2.8 Bcf a day of new capacity. And this was really on – these projects are demand-driven projects on Transco. And this new capacity enabled Transco to set one-day and three-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 segment, and importantly, greater than 40% complete on the compressor station. So difficult winter conditions up there, but 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 for 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 2019 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 heels 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, as we continue to add volumes on our Wamsutter system in Wyoming. So all in all, a great quarter with significant 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, it came in about 3.5x, and on WMB at about 4.4x, which you can see is well below what we were targeting. You need to add about 0.3 or 0.4 to the actual number when estimating the rating agency calculation. And 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 2018 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'll continue to drive our strength in our balance sheet.
Now, let's move on to slide 6 and take a look at our 2018 financial guidance. 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 $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. So, 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 dropped 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 on to Northwest Pipeline via regulatory accounting charges due to the Tax Reform, even though the revenues we receive 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 million 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 two 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 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 spend 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, begin with the big pieces. By virtue of our sell of the Geismar olefins facility in July of 2017, you can see the $72 million step down there. That's just the EBITDA that was associated 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 end 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 very strong Ohio River Supply Hub growth.
The continued growth in our business and asset integrity work is leading to modestly higher operating expenses in 2018, as you can see. 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 what would be EBITDA before the impacts of these non-cash 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 2018 and 2019, but increasing revenue recognized beyond 2019 versus what we expected on the old accounting standard.
If you'll recall, it really was just driven by the fact that the period of the MVC was the period that we were amortizing that period over the new accounting standards require us to smooth that out over the entire life of the contract, not just the period that had the MVC 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 multi-year guidance, however, we do expect an even stronger level of growth in 2019, 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 2017 and 18, we thought it would be helpful to give you at least a glimpse here into what we expect coming off of Transco into 2019.
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 in 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 of revenue from the 2017 Big 5 projects. Note that in 2017, we only had $140 million partial year impact of the Big 5 projects that were placed in service during the year. And in 2018, 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 what 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 – sorry, that was in 2019. And you also begin to see the impact of Atlantic Sunrise and Garden State here in 2018 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 2019 on top of the $140 million contribution in 2018.
And finally, as I mentioned earlier, Transco is also working on its next rate case. And I know there's a lot – 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 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 rates and 50% cost-of-service-based rates. It's the cost-of-service-based rates that are subject to changes with each of Transco's 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 a new cost-of-service rate. Certainly, operating expenses are intended to be recovered in the cost-of-service rates. 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've continued 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 rates, which will also be a factor. There are two primary ways that the lower corporate tax rates will impact the pipeline's rates. First is simply the lower cost that lower tax rates represent the provision in our rates for current and future taxes will be lower and now that the corporate tax rates decreased, so that's kind of a forward-looking piece.
The second impact is represented in the non-cash regulatory charge and related regulatory liability, which you saw when we discussed the fourth quarter results earlier in the call. This liability represents an estimate of the value that will be returned to shippers to account for the deferred portion of 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 rate making process on Transco for the cost-of-service contracts will likely be in negotiation that takes all of these factors into consideration as we jointly determine the fair cost-of-service rates for our max 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 seven 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 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 in-service date for the project. But consistent with past practice, we include some additional time when forecasting revenue and EBITDA growth into our future business plans.
Beyond this 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 were 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 commitment, as I mentioned earlier. But new opportunities continue to emerge. And, in fact, the potential project list has now been backfill and now stands at over 20 projects.
Moving to the Northeast Pipeline infrastructure build-out, we'll 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 sixth major expansion of the Susquehanna Supply Hub. And in addition, we expect to complete the fifth 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, that'll come on likely in 2020.
We're also very excited about our recent announcements from Shell on their Whale prospect and Chevron on their Ballymore prospect. Here, a few weeks ago, both these major prospects got announced. And just to kind of pin that down a little closer for you, the Whale prospect is within 15 miles of our Perdido oil and gas export pipeline, which come up onto 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 Whale are clear indications that Deepwater developments remain highly commercial. And Williams is in the absolute right spot in both the Eastern and 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 heels of the two Chain Lake expansions I mentioned earlier, now comes 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 continue 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, in the best basins, 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 invested capital will be extended by the latest round of this customer activity.
So now, I'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 to fund our stated forecasted capital projects through our full planning horizon. We're able to do this while maintaining a strong balance sheet and leverage metrics and healthy coverage of both WPZ distributions and WMB dividends.
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 the 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 our first question.
Thank you. And we'll take our first question from Jeremy Tonet of JPMorgan.
Good morning.
Good morning.
Want to start off with Northeast gathering and processing there. And the O&M had stepped up a bit quarter-over-quarter there. I was 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.
Good morning. This is Michael 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 in 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 additional operating costs that come along with that, whether they be electric power for 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 facilities that came online, our new employees. I mentioned the additional electric cost. But we also had emergent 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 mine 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 – our GAAP numbers, but those obviously affected us there. That actually lowers our costs going forward in the future but had a onetime 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 under way, 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 on line as well next year.
So growth is driving cost higher, but certainly we're watching very closely operating margin associated with each one of those franchises. And we've 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, 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 a lot of additional business for us, as I indicated. And our Oak Grove expansion is a great example of that.
Great. Thanks. And maybe just touching on Southwestern to build on there, if you could just update us there as far as how the ramp progressed during the quarter and how you see that kind of going into 2018?
Yeah. Maybe just – this is Alan. I'll just add a little bit there. First of all, in the Southwest Marcellus area, Southwestern's 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 intend to bring on new volumes. And as they do that, our capacity that we make available for them on the processing expand and their minimum volume commitment to expand, to stand behind those investments that we make. And we have seen them increasing those requests for service, which drive 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've been very successful out there. And we're 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 counterparties. But the consolidation we're seeing out here in and around our acreage is really starting to drive a lot of activity and growth.
Got you. Great. And just one 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.
Yeah. 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.
Two very large wells that were producing – I think they got up to almost 400 million a day of production off those two wells of dry gas that came across that platform. I'm not going to get into Exxon's business there, but we've seen that production decline off dramatically. And we don't right now expect that production to come back on line 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 2018 numbers, it was about $95 million in terms of reduction of what we would have – or I should say definitely in terms of what we saw in 2017, it was reduction from 2017 to 2018 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 of that kind of significance to backfill that here in 2018. But there's a tremendous amount of prospects there in the Keathley Canyon area that were – 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 in a great spot.
That's very helpful. I'll pause there. Thank you.
Thank you.
And our next question comes from Jean Ann Salisbury from Bernstein.
Good morning. I think you've said before that after Atlantic Sunrise comes on line, 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 one or two 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's been running up fast on that list with all the great business that we have within there in Susquehanna Supply Hub and then – and Atlantic Sunrise comes on. So, I think that's really going to drive that. But if 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 that. Obviously, Southwestern is emerging but not anywhere near yet, where we see Cabot as an E&P customer.
Got it. That's really helpful.
Alan, you got anything to add to that?
No. I think that's great. That's right.
Thank you. 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?
Yeah. I think, obviously, we stay very close to Cabot. And they've done a great job and 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, too. It's pretty remarkable to me to see what they've been able to do in such a very low price environment that they've been exposed to. And so, I think they are capable of operating in a very low price 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 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 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 that 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're seeing. And it's right in line with what we laid out last year in our Analyst Day as we look (48:27) 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.
Perfect. That answers my question. Thank you.
Thank you.
And our next question comes from Christine Cho of Barclays.
Good morning, everyone. I wanted to start off in the West. The volumes are good. Can you just remind us if the Haynesville contracts are higher margin than the other G&P areas in this section?
No. 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 two systems out there. So, I would say, our rates out there today are in line with the market. In terms of 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, you'll recall, we did a little expansion back in August of last year.
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 systems 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 it. 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, our unit operating costs, they're 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 gross or net numbers to you, as I think Atlantic Sunrise is consolidated in your financials, but the non-controlling interest line is below the adjusted EBITDA.
Yeah. No, you are correct. That is the gross number.
Okay. And do you have like a net...
That is what goes into EBITDA, and then there'll be a minority interest deduction number.
Okay. And then, lastly, WPX sold their San Juan acreage. And just wanted to see what kind of impact you expect to see from that, if any, and to confirm that the contracts will transfer over to the new owners.
Yeah. First of all, we haven't seen the contract shift yet, so obviously, we'll take a look at that as we do in 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 concluded 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 that it needs in the Mancos oil play there is a positive thing. And we're 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.
Great. I'll leave it at that. Thank you so much.
Thanks, Christine.
And from Goldman Sachs, we turn next to Ted Durbin.
Thanks. 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 in Transco?
Yeah. Ted, I would just tell you, that 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'll form the basis for that rate in August. But I would tell you, the numbers on Transco are big and it takes a lot (54:00) direction to move 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've 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 costs, particularly around Transco, please.
Yeah. Ted, thanks for the question. First of all, you could draw the conclusion – without seeing the details, you could draw the conclusion that our expansions are really driving a lot of that cost, and that's just not the case really. The cost is being increased as we go through the process of doing things that you might consider to some people would look like maintenance capital, but by the details of the rules (55:16) are not maintenance capital.
So, for instance, doing hydro testing on pipeline and doing repairs, all of that, it winds up in expense. We have a lot of that to do on the Transco system. And certainly, because we operate in such 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 cost 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 the 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, so that just becomes an estimate. And until you actually run the test, then 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 costs 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 from 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 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?
Yeah. 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 reimbursed capital that would show up as capital spending, but in fact, it gets reimbursed. And so, that's about maybe 20% or so of that 15% maybe.
And then, in the Northeast, a lot of growth going on, and with the sixth expansion that I talked about in the Northeast as well as a 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 will probably be the Niobrara with the growth that's going on there.
So, that probably will wind up being more of a 2019 issue perhaps, but maybe start spending on that. So, that's really driving most of it is actually in all three areas. The largest of those right now though is the Northeast in both the Susquehanna County area as well the Ohio Valley Midstream area.
Perfect. I'll leave it at that. Thank you very much.
Thanks, Ted.
And up next is Shneur Gershuni from UBS.
Hi. Good morning, guys. 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 sort of seemed that there was a goal to reduce leverage by about $5 billion. You did the equity issuances, you've had some asset sales, and EBITDA seems to be recovering and so forth. 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 close to paying off its revolver in the second half of this year?
Yeah. I'll take the last part of that. 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 would 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, it's not a similar 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 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 raise obviously is a place 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 six months from now in terms of when we're up against that. So, stay tuned, but I'd 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.
Yeah, sure. So, 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 dividends. So, we'll continue to pay that revolver down. And that obviously puts us in the third quarter or fourth quarter when the revolver's 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 leverage will tick up somewhat as we get to the end of 2018, and then once we get the full benefit of Atlantic Sunrise 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're really talking about mid-level investment grade, not BBB- but a solid BBB ratio. We think we need to be in the, probably, 4.5 to 4.75 times 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 2019, we can make a pretty strong argument 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 on line, Rover is expected to come on line, 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 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 2.5 times EBITDA multiple?
Yeah. 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 in very short term and just drilling when the pricing is there. Obviously, they can turn these areas when the infrastructure is already in place, 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're 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 takeaway capacity.
And so I think we are certainly continuing to see expansion going. I think people are getting better and better at getting their cost down on the reserves. And so I think that's pretty promising for the Northeast in terms of volumes.
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 awhile 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 our Southwest Pennsylvania for the rich Marcellus.
So I'd say, feeling pretty optimistic. But I do think, to answer your question, it's very dependent on what it produces, a 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.
Yeah. I would tell you, we happen to be in the right spots. And so that's the good news in that 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're 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 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.
But they've got to make sure there's room in the infrastructure, both on their platform and in our pipelines to get that gas and oil out of there. And so that's kind of what you're seeing managed.
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 out in this play.
Great. Thank you very much. Really appreciate the color today.
Thanks, Shneur.
And our next question comes from Colton Bean of Tudor, Pickering, Holt & Co.
Morning. Just wanted to follow up in 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 the 2018 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?
Yeah, 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 obviously, they've given that good thought and – before they make those kind of commitments. But that's basically what we generate our forecast off of. I would say, we have very little speculative drilling built into our forecast (1:09:35) off of that.
But I would say, as we look into 2019, first, 2018 is strong with I think about a 13% increase from the fourth quarter to fourth quarter, so exit rate to exit rate. And so that's very identified right now in terms of where that volume's coming from.
And as we look into 2019, we're seeing a similar pull-through. But again, so many of our contracts are either cost of service, which requires long-term planning, or minimum volume commitment-backed contracts. That's really what's driving our forecast.
Okay. Helpful. And then just to circle back to the West segment. So it looks like you're up about $250 million (1:10:28) in the gathering piece. So you mentioned the Haynesville, but then 8 of the other 10 – or I guess eight of the other nine were also up. Can you just frame, I mean, what the magnitude was? Was there any meaningful contributors there or predominately Haynesville?
Haynesville was the biggest I think behind that probably on a percentage basis. (1:10:51)
On a percentage basis, we saw 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, though across the board, saw pretty good improvement across all of those. The Eagle Ford was up almost double digits there as well, so.
Yeah. I think on an order of magnitude, I think, Haynesville and Eagle Ford were the two biggest drivers. But on a percentage basis, the Niobrara was pretty strong. And I would tell you, given the current activity, we expect that to continue to be a pretty strong percentage driver, even though on an absolute basis it doesn't have that much impact.
Got it. Okay. And just a final question here on maintenance. So relatively light versus 2017 guide. Is that tied at all to your conversation around the O&M spend and some of that transition from what you would consider maintenance CapEx to the operating expense line? Or just came in lower than expected?
Well, I would say – this is Michael 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 wouldn't likely shift into 2018 from the appearance of a lot of it. Was just a lot of that work that was in process, but just didn't get completed in the fourth quarter. So we are seeing some of that shift into 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 in some of that work that we just don't get completed, and it shifts 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 but some of that slipped to this year?
No. I wouldn't characterize it that way. In fact, we're seeing 2018 slightly ahead of where we've anticipated 2017 to come out. We're seeing a lot of work, as we indicated earlier, in our Transco system, but not only on the expense side, but on the maintenance CapEx side as well for integrity and reliability projects.
So, yeah, to be clear we are expecting an increase in maintenance capital from 2017 to 2018.
But the guides are effectively flat? $500 million both years?
We came in below that $500 million in 2017. So, I think, we came in at $440 million...
Yeah. That's correct.
That's right.
...in 2017.
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 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 till we get towards the end of the year. So, we widened the guidance a little bit to reflect that.
Yes. All right. Well, thank you, guys.
Thanks.
And from Citi, our next call comes from Eric Genco.
Morning. 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 it and say, if you 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 and other entity? But then is it basically – as people are sort of anticipating the potential for a consolidation of the two entities is it just 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?
Yeah. All of that. There's, obviously, a lot of things to consider there. But, as you know, the Tax Reform, of course, pushes out the date by which we would be a cash tax payer at WMB, which is obviously one of the benefits of getting that tax stuff up (1:15:24) first. And secondly, ultimately, the tax rate that we're paying just got lowered as well. So, I would just say that, that driver is somewhat lessened as a result of Tax Reform bill as we look out there.
So, John?
No. I think you're – I mean, obviously, and Alan alluded to this earlier. When we get to that point, we'll be making a relative return decision and if WMB appears undervalued, maybe we buy back WMB shares. If WPZ seems undervalued, maybe we buy back 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, just generally, as it relates to that entity, I think we'll have to take a look at how the MLP space is doing in general.
I think MLP is a tool to race capital over the long term if that market were 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 generally trending sideways, then, you have to (1:16:32) 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 on – and just 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 multiyear 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 2017 to 4Q 2020 in those areas is pretty much limited to Atlantic Sunrise's capacity?
Yeah. 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, we have some expansion capability on Atlantic Sunrise. So, I would just say, if the folks in 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 that's – what 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's 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, the market takeaway, there's plenty of market growing to the south. And we were very well-positioned to be able to get that gas there through either expansions of Atlantic Sunrise or Diamond East, as I just mentioned.
Okay. Thank you very much. Appreciate it.
Our next question comes from Darren Horowitz of Raymond James.
Hey, guys. Just a quick one for me. When you think about the EBITDA buildup, not just for 2018 but going into 2019 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 Atlantic Sunrise line contributions into the Susquehanna and Bradford systems in addition to Garden State versus maybe just more aggregate takeaway capacity alleviating basis pressure in the basin? And then, into 2019, how do we think about the construct of that EBITDA buildup versus what could be rising O&M expenses again?
Darren, make sure I heard that correctly. First of all, last quarter out on the buildup, the cost buildup that you see there in 2018 certainly would carry – that cost increase would certainly carry into 2019, 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 2019 period as well. So, I think that answers that part.
If would 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. Yeah, 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're to look at Cabot's slide 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 smart on that.
But I also would remind people that as these big takeaway projects come out of the Southwest part of the Marcellus or Mountain Valley, Atlantic Coast, as those come online and get attached to growing markets there, that will pool gas off of systems 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 – we have 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 two 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 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 margin uplift, if you will, that we spoke about at last Analyst Day.
Thank you.
Thanks.
And we'll go next to Chris Sighinolfi of Jefferies.
Hey, guys. It's Cory (1:24:15) filling in for Chris. And thanks so much for taking time, so much extra time to answer all of our questions. Just two really quick ones for me. The first one is just want to make sure we heard the Transco timeline correctly. So, that on slide 8, that $140 million walk from 2017 to 2018, that assumes July and service of compressor. And you said a few months after that, it would be the greenfield pipe portion that would start contributing?
Right. Yeah. I can take a little bit of more filler 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 process, because you have to go through on the compressor stations to complete your commissioning activities, where it's a lot quicker on the pipeline systems. You're really just commissioning the 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 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, 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, the contribution, yeah?
Yeah. That EBITDA, that $140 million split. I don't know if you can for us.
Yeah. I 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'll 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. The percentage of annual increase is staying the same, but the annual versus quarterly distinction is new.
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 raisers, and so we were just pretty well staying in line with what we see really out of the more pure market for WMB. And so, that's really the driver on.
Understood. All right. Thanks so much again for the time, guys.
Thank you. Okay. Go ahead.
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.
Great. Thank you. Lots of great questions. Thank you, all. 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-priced gas out of the ground. We think it's a really positive thing for us, both on the LNG development and those markets as well as the development on gas fired generation, and I think we'll see some of that this summer, that demand start to pick up as well.
So, really excited about how the fundamentals are supporting our business and especially pleased with the continued improvement in 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.