威廉斯 (WMB) 2017 Q3 法說會逐字稿

Good day, everyone, and welcome to The Williams and Williams Partners Third Quarter 2017 Earnings Call -- Conference Call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead.

Thanks, 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 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 will turn it over to Alan Armstrong.

Thank you, John, and welcome, everyone. I want to begin by introducing John Chandler to this call as our new CFO. He joined Williams in September, and he's no stranger to many of you obviously. John enjoyed a long tenure at Magellan as CFO, and he actually went to Magellan when we spun it out from Williams. We're very pleased to be welcoming John back to Williams, and you'll hear more from John later this morning. Of course, John is replacing Don Chappel, who is retired from Williams. And I want to thank Don for all of his contributions to the company, and we certainly wish him well in his retirement.

As for the quarter, I'd like to start by thanking the team for another strong quarter of fee-based revenue growth, driven by the project execution front as we continue to bring projects into service on time and within our budgets. Importantly, we also continue to win meaningful new business, which will keep our project execution teams busy for many years to come. The large-scale advantaged positions we've established continued to generate growth, as evidenced by our strong results with the year-to-date adjusted EBITDA up versus year-to-date '16 despite the sale of over $3 billion of assets that generated $110 million of EBITDA in the 9 months ended September 30, '16 and the impact of 2 hurricanes that shut in volumes from offshore producers.

We substantially reduced our direct exposure to commodities. And as a result, our current business steady growth is both predictable and transparent, as it is being driven by consistent fee-based revenue growth under long-term contracts. Our strategic focus on natural gas volumes continues to deliver results. So far in '17, we placed 4 of our big 5 Transco expansion projects into service, including: Gulf Trace, Hillabee Ph. I, the Dalton Expansion, and the New York Bay Expansion. With the fifth of the big 5, the Virginia Southside II project, expected to be placed in service during the fourth quarter of this year.

The incremental capacity from our fully contracted Transco expansion projects going in service so far this year reflects a 25% increase in Transco's design capacity. And year-to-date, Transco's transportation revenues have increased $74 million, a 7% increase over last year and this is even though most of those '17 projects are being placed into service in the last half of this year.

So along with our successful project execution, I'm also pleased with how we've strengthened our balance sheet and credit profile, significantly reducing our debt and lowering our overhead expenses. In fact, year-to-date, in '17, Williams Partners has reduced long-term debt by $2 billion and increased cash by over $1 billion. This reduced debt level and increased cash balances positioned us to self-fund our attractive slate of growth projects using cash-on-hand, retained operating cash flow and debt, without the need to issue public equity, all while maintaining solid investment grade credit metrics and coverage.

At the corporate level, WMB has paid down $372 million in debt, and total adjusted overhead expenses have been reduced by about $40 million when compared to the same period in 2016, as we were able to realize overhead reduction in several ways, including moving from 5 operating areas to 3, and closing the Oklahoma City office in June of this year.

So let's look at the results for the third quarter of '17 and looking at the GAAP results first. WPZ delivered $259 million in net income in the third quarter of '17, and WPZ's adjusted EBITDA was $1.1 billion. Our current business segments, the Atlantic-Gulf, the West and the Northeast G&P, so those assets that we pertain, the businesses we've retained, combined to increase our adjusted EBITDA for the quarter by about $13 million. However, the full WPZ comparison shows a decrease in our third quarter adjusted EBITDA results versus third quarter of '16 of $88 million. Of course, this was driven primarily by the absence of over $100 million in adjusted EBITDA contributed from the NGL & Petchem segments earlier. And of course, these were sold by the partnership. And this included the Geismar olefins plant, which we sold in July of this year, the associated RGP Splitter that we sold in June of this year and our former Canadian businesses that were sold in September of 2016. I would add here that our third quarter '17 adjusted EBITDA increase from our current businesses includes an unfavorable impact of approximately $8 million from Hurricanes Harvey and Irma, and contract restructures that lowered the West area results. So those are both contract restructures that we did in the Barnett, as well as in the Niobrara area. So we're about to roll out of those -- the periods of comparison to those, but those certainly had impacts on the West.

Looking to DCF for the third quarter of '17. Williams Partners generated $669 million in DCF compared with $795 million in DCF for the third quarter of '16. In addition to the unfavorable change related to the big asset sales, the DCF for third quarter of '17 has been reduced by $59 million for the removal of noncash deferred revenue amortizations that were associated with the fourth quarter of '16 contract restructuring in the Barnett Shale and Mid-Continent region. So we mentioned this reduction in last quarter's call as well. Partially offsetting the unfavorable changes was a $37 million decrease in interest expense.

Importantly, WPZ coverage for the quarter came in at 1.17 and puts us at 1.24 year-to-date. The cash retained due to this healthy coverage supports further investment in our high return growth CapEx portfolio.

So now we'll take a look at each of our segments. Starting here with the Atlantic-Gulf. The adjusted EBITDA for the Atlantic-Gulf came in at $431 million, a $3 million decrease from the third quarter of '17. The year-over-year comparisons were impacted by the short-term benefit we had in Q3 of last year, where we were gathering and processing gas from a competitor's Pascagoula plant, and so that we had a big lift in the third quarter of last year, as you'll remember, we pointed out. And in addition to that, in the third quarter, we had impact from both Hurricanes Harvey and Irma.

Transco's growth project contributed $46 million in fee-based revenues incremental. So a very good topline quarter here for Transco. Partially offsetting the increased fee-based revenues were increased O&M expenses associated with Transco's required integrity and pipeline maintenance programs. These increased expenses are something we've been expecting and planning for. But I would say, due to the timing of work and invoices, expenses were slightly more concentrated here in the third quarter as usual. So overall, for the year, we're on plan and certainly within our expectations, as we provided guidance there. But we did have it pretty lumpy here in the third quarter. A lot of that is just because we have the ability during this part of the year, right before we've got lines tied up for winter service, we've got a period that we can get in and go and get a lot of that work done, and we certainly got a lot of that done here in the third quarter.

So now turning to the West. For the quarter, adjusted EBITDA came in at $426 million, down by $7 million versus the third quarter of '16. Fee-based revenues were down on an adjusted basis primarily due to contract restructures, and also EBITDA from JVs was lower due to the Delaware Basin joint venture sale from the first quarter. So recall, in the first quarter of this year, we sold our interest in a Delaware Basin JV to Anadarko -- or sorry, to Western Gas.

These structural impacts were partially offset by continued tight O&M and SG&A expenses, and so really proud of the team continuing to put a lot of pressure on our overhead cost and our -- direct O&M cost in the West. Some good news, I will tell you, for the West. We did see increased volumes sequentially. So when we look at the West, gathered volumes up 5% versus 2Q of '17. You'll recall, in 2Q, we said we expected to see things turning that way as we were starting to see volumes come back mostly due to the strong volume growth we saw in basins like the Haynesville system, and we are seeing the big volumes in the Haynesville coming on out there, and we're seeing this continue in the fourth quarter. I'll provide a little more on that in just a moment.

Now looking to the Northeast. Overall for the third quarter, our Northeast adjusted EBITDA increased $26 million compared to the same period last year. The current year benefited from higher proportional EBITDA from our Bradford County JV. Our Northeast volumes were up over 0.5 Bcf a day, a growth rate of over 8%. And looking at 3Q of '17 to 3Q of '16 on all these -- on operated systems. So this overall gathering growth was driven by both the Bradford Supply Hub and the Susquehanna Supply Hub growth. This growth was partially offset by lower Utica volumes. But again, just like we've talked about a little bit in the West, we were pleased to see the Utica volumes begin to turn around with sequential growth from 2Q of this year. And I will just note on that, most of that turnaround in the Utica is actually on our Flint system, which serves the Dry Utica.

So now let's look at year-to-date and take a look at what happened in our year-to-date results. In spite of the hurricanes and the removal of $110 million from our NGL-Petchem EBITDA, Williams Partners still delivered year-to-date GAAP net income of $1.21 billion, and we delivered adjusted EBITDA year-to-date of $3.32 billion, an $8 million improvement from the corresponding period in 2016, primarily due to increased fee-based revenues, increased commodity margins and an increase in proportional EBITDA from joint ventures and lower overhead expenses. Adjusted EBITDA from the retained businesses was up $118 million versus the same 9 months in '16 for our retained businesses. And so that is from the Atlantic-Gulf, West and Northeast G&P. So noisy, as we got some of these asset sales coming out here from -- on the year-to-date numbers, but overall, really pleased to see the way our retained businesses are performing.

Year-to-date coverage of WPZ is now 1.24 on the back of a $2.1 billion in DCF, and this very solid coverage excludes the $175 million of EBITDA that is revenue amortization associated with the Barnett and Mid-Continent restructuring. So just to remind you on that, we include that earnings in the -- obviously, in the EBITDA calculation. We included the earnings, but we [pulled] that out of DCF.

So now let's look at some of our recent achievements, as we continue to build long-term sustainable growth in the business. Several of our recent achievements contributed directly to our performance this quarter, including 2 more of our 5 planned '17 Transco expansions placed in-service during the quarter. Those would be Hillabee and Dalton. And on Atlantic Sunrise, we started construction and have already placed a portion of Atlantic Sunrise into early service on September 1 of this year, providing about 400,000 dekatherms a day of firm transportation service on Transco's existing mainline facilities. And of course that served delivery points as far south as Choctaw County, Alabama. So we're really excited to be starting to see the Transco system turn around and be able to deliver volumes to the south. And I can tell you that's very much needed as we're seeing a lot of demand growth occur in the Southeast on our system.

We are seeing exciting spurt of growth in the Haynesville. In August, we placed into service additional CO2 treating capacity. And as a result of customer activity and our increased treating capacity, volumes on the Haynesville system grew to 1.45 Bcf a day here in late October. And we now expect to see volume growth of over 30% this year in the Haynesville, making it our fastest-growing basin this year across The Williams assets.

Also, as many of you know, we also recently won new acreage dedications from Southwestern in West Virginia, and we agreed to provide up to 660 million a day of processing capacity. And by the end of the third quarter, we were already processing an incremental 100 million a day of Marcellus wet gas from this new dedication. And with the addition of this 100 million a day, the exit rate for our 3Q '17 OVM processing was approximately 540 million cubic feet a day. And Southwestern is rapidly growing their wet Marcellus volumes on this dedicated acreage, and we are really thrilled to have the opportunity to help them maximize the value of this prolific acreage. We've got a great relationship with Southwestern, and the teams are working very well to maximize the value of that acreage.

We also enjoyed significant achievements that we expect to contribute adjusted EBITDA in the fourth quarter. The Transco New York Bay Expansion Project was placed in service here on October 9. And this was the fourth of our 5 Transco plant expansion projects. Transco continued to push new expansion opportunities forward as well, receiving a favorable environmental assessment on the Gulf Connector project and applying for a FERC certificate for Rivervale South to market, a new fully contracted 190 million a day Transco expansion to New York and New Jersey markets. It's just another project that is supplying both power demand and replacing fuel oil with cleaner and more affordable natural gas in that region.

And now let's look at what's coming soon. Our commitment to continued growth is highlighted on this slide. Again, Virginia Southside II is our fifth Transco expansion project this year. And so we're really excited to see that conclude, and looking forward to that coming on sometime here in the fourth quarter. We placed Phase I of the Garden State project in-service in September as well. That's kind of a little bit of a bonus project on top of the 5, and we will be placing that full project into service in the (inaudible) quarter of next year. So that project is going well too.

We briefly touched on our Southeastern Trail project last quarter. We were pleased with the results of the successful binding open season. However, we are pursuing an even more strategic opportunity that will serve those open season customers, and provide a strategic expansion that will serve the broader industry with direct connection of low-cost reserves to those -- to these growing demand centers. So we certainly heard from the market that they needed the additional supply, and we're trying to utilize that demand to make an even more strategic expansion. So certainly not going to step over the top of the great opportunity we have there. But we are taking our time here to make sure that we make the very most we can out of that very valuable southbound expansion capacity on Transco.

In the Northeast, our big Susquehanna Supply Hub expansion remains on schedule, with an expected in-service date in late 2017. This expansion done for Cabot should drive higher volumes in Susquehanna even ahead of the Atlantic Sunrise project. And this area just keeps on delivering growth, and we are already planning the next big expansion for this area.

In Wyoming, we were able to bring more volumes on to our Wamsutter system after placing our Chain Lake compressor station into service in October. And this is another project that was done on time, and actually, this went under budget, to meet the growing demand of a key customer there in the Washakie basin. And we're already exploring additional expansion opportunities for Chain Lake with 2 other customers in the region, and this is really an interesting area, where we're seeing an emerging new play be developed in an old field in that area that was originally completed with vertical completion and a real opportunity up there now for horizontal application in that area.

With regard to guidance. Our guidance for 2017 EBITDA and DCF remains firm, as does our previous distribution in dividend growth rates. We plan to announce our 2018 financial guidance with our fourth quarter '17 financial results. And of course, that will be in the first part of 2018.

So as I wrap up, I'd emphasize, we're pleased with the execution and our clear line of sight on long-term steady growth. After substantially reducing our direct exposure to commodities, our current businesses' steady growth is being driven by consistent fee-based revenue growth via long-term contracts. And we expect '18 and '19 to be exciting years as we finally see the bottlenecks in the Northeast clear to let the value of our long-term strategy be realized, both in the Northeast and on our Atlantic-Gulf system. So really pleased with the way things are looking right now in that area.

And then finally, I want to again thank Don Chappel for his great work at Williams and I wish him well in retirement, and I welcome John Chandler to this call as our CFO. And with that, I thank you very much and we'll turn it over for questions.

(Operator Instructions) And our first question comes from Jean Salisbury with Bernstein.

The deal with Southwestern was much more incremental volume in that area than what I had originally modeled. Without getting into too much customer detail, can you speak to whether you expect tariffs on that contract to be generally in the range of your existing tariffs there? Or if you had to take a material reduction to get the deal done?

Good question, Jean. I would tell you that the pricing on that was pretty similar to our earlier pricing. I think the area that we did provide some incentive on was for the Utica volumes. But we do have a great service offer up there and we certainly offered that because we have existing capacity there with OVM. So I would just tell you, we're very pleased with the pricing on that, and provides us a very high incremental return in that area. Having said that, of course, we've invested a lot of money in the first place up there, so you would expect those higher returns. So overall, I think we priced at about like we expected. It's just that we've got so much latent capacity to use there that we've got some real big incremental initial cash flows that come off of that business as a result of available capacity we have in the area.

That makes sense. So in terms of the EBITDA per Mcf range, it's sort of similar to what you had said at the Analyst Day?

Yes. Yes, no change. That is a positive impact to what we showed there at Analyst Day.

Great. That makes sense. And then as a follow-up, I know you probably can't comment too much more on Southeastern Trail. But is the way to think about it that you have enough commitments for the low end of your volume options on the project? And what you're working on is incremental volumes that maybe would go further on the system as well?

Yes. Maybe another way to think about it, I would just say, we have a very attractive project that just utilizes the capacity on the system, and one that certainly rivals any other project that we have on the system from a return standpoint. But we really want to make sure because there's very limited amount of that very precious capacity coming south. And the more capacity we do, the more expensive it gets. And so it's kind of a reverse economies of scale on that just because it requires more and more capital investment as we expand that capacity. And so we want to make sure that we're getting everything we can out of that investment, including strategic benefits that would include connections to low-cost reserves. And so great work by the team. We're really working well with a number of players on that. I would tell you, I'm pretty optimistic. But the good news is we have the Southeastern Trail project if we choose to go forward with that. That is in hand, and we're prepared to do that if we can't get the other deals done on a timely enough basis.

Okay. That makes sense. So if you choose to do a larger volume project that would have higher cost, you need to charge the same tariff to everyone. Is that the balance that you're working on?

No, it's a little more complex than that, but that's probably about as far as I want to go with it.

And our next question comes from Jeremy Tonet with JPMorgan.

Don, good luck in retirement. John, welcome aboard. I wanted to start off with the O&M. It seemed like there was a bit of an uptick this quarter in the Northeast and in the Atlantic. And just want to see if there was anything to this, if this is one-time in nature or seasonal or is this kind of a new run rate? Any color you can share there?

Let me turn that to our COO, Micheal Dunn.

Yes. First, in the Northeast, a part of that was a true-up of a tax issue. And so I wouldn't say that, that was a -- obviously a run rate issue. The majority of that Northeast was a portion of that as well as some additional work that we were doing for landslide mitigation that's not typical, and that's pretty lumpy work, depending on when we see something we need to go out there and fix. So that's really what drove issues in the Northeast. On the Atlantic-Gulf, and specifically on Transco, Alan touched on that earlier in his comments in regard to our integrity work that's underway there. And typically, we see those costs every year rise in the third quarter because that's our opportunity to get the work done. And like a lot of our peers in the industry, as well as our customer companies, there's a lot of integrity work underway across the U.S. on the natural gas infrastructure. And a lot of that is driven by either the regulations or the records reviews that a lot of companies are doing. And once you find the issues within your records, and a lot of these pipes are quite old, and when you research those records, you find that maybe you need to go out and do some hydro tests of some areas where you're not certain of the records covering the entire area where it was originally hydro tested. And so we've taken on a lot of that work this year, and we would expect to see more of that work next year as we continue to go through those records, as well as just our ongoing integrity management programs that we're undertaking across the assets. And that's really what we're seeing on the Transco system. I would say that quarter 3 is typically our higher quarter for spend. And you certainly can't extrapolate that across 4 quarters of a year to come up with an annualized number. It's pretty typical, if you look at our history, higher the third quarter.

That's helpful. Thanks for that. And just wanted to touch base on the Central Penn Line a little bit more, and any more thoughts or details you can provide around timing? And if that could be something that comes online sooner or later or just any other details as far as the kind of mid-'18 in-service, I think, you've talked about?

Right. Yes, we're really pleased right now that we started construction on the Central Penn Line, which is the key greenfield infrastructure for Atlantic Sunrise. And we are targeting a mid-2018 for completion of the work on that pipeline, as well as our compressor stations. And I will tell you that, obviously, weather is a big factor there with the winter construction for the pipeline and compressor station. But we're off to a good start so far, and we're still targeting, as far as our project teams are concerned, a mid-2018 in-service date for the completion of the work. Then there will be commissioning activities that occur after the mechanical completion of the pipelines, as well as the compressor stations. So as you are probably well aware, we typically risk-adjust the revenues that you would see coming through in our forecast. But right now, we're marching forward for a mid-2018 in-service date for the facilities that we have underway right now.

That's helpful. Thanks. And then just one last one. Was curious on your thoughts in what you're seeing with Northeast basis differentials? And specifically, some of the commentary we've been hearing from some of the producers regarding potential volume curtailment, given these tough differentials, any thoughts you could share there?

Yes, we certainly did see some degree of curtailment, like we often do during the shoulder months. And prices certainly were very depressed because there was very little local loads. So if you think about what drives the volumes inside the circle, if you will, or within that region, the weather pattern was very mild there. And so very little local load there this third quarter, which obviously put a lot of pressure on the basis. I think in addition to that, you have a lot of people building up reserves, expecting Rover to be on schedule, on time, and when that -- that's hard to plan for when it moved as dramatically back as it did. So you probably had a lot of capital investment ahead of that, that was too late to turn it back. So you probably had a little bit more production, a little more gas on gas competition without any real exit from the area. Just kind of move the circle out a little bit, but not really in each market. And so I think that it's going to take some of the projects that Columbia has. And then ultimately, Atlantic Sunrise and of course, finally when Rover gets in the first quarter, gets out into some new markets, to really see that ease. However, I -- we always see here in the fourth quarter and the first quarter, if we get to normalized weather, we will see the basis differential flatten out just because the local load will be coming on. And in addition to that, I would say we are seeing some new power plant load that will be coming on next year. And so those are all positive things that are moving us forward towards better basis differential. But certainly, the third quarter is pretty painful and we did see some volume shut-ins on our systems.

And our next question comes from Ted Durbin with Goldman Sachs.

First question is just coming back to Atlantic Sunrise and the Central Penn Line. Now that you've gotten into construction a bit, I wonder if you can fine tune your CapEx assumptions. We thought that this is around $2.6 billion, I think, on a gross basis. Is that a good number for the project?

Yes, we still are holding at that number. We obviously keep some contingency within our project forecast to remedy any situations or issues that arise during construction. But we believe that's still a pretty good number.

Great. And then I know you're just starting to get this in-service, but as you think about the 42-inch line, I believe, is there an ability to increase the capacity beyond the 1.7 Bcf a day that you've put in there? And what are your thoughts on doing that as you see the demand to get out of the basin?

As usual, we'll wait and see if there is -- or enough demand for projects. We do have some other projects that we're looking at as well, expanding out of the basin. And so I think it is a little bit to be determined. So if you think about other projects, like Constitution, probably be determined. That will probably be the next expansion. And so I think people will kind of wait and see on that. We also have another a couple of other projects that we haven't provided any announcement on, that we're working on that could serve to get volumes out of the basin as well. So I'd say those probably go first. And as you know, we pretty well got a -- get the existing project. We're working on build before we talk about expansions on another one, and so that's where we stand today. But in terms of its expansion (inaudible) certainly, physically, there is expansion opportunity on the system.

Great. Actually, that's helpful. And then I'd love a little bit more color please on the West. You mentioned the Haynesville really picking up, and sounds like momentum into the fourth quarter. Is that the main driver of that 5% increase in volumes? And then how do we think about, call it, unit economics, I guess, if the Haynesville is where you're going to see an uptick as we move into 2018? Would that be positive or negative to your overall unit margins there?

Yes, great question. I would say in the West that the Haynesville is probably just slightly above our average on unit margins against all of our other West gathering business. And so it's very attractive basin for us to see growth, especially at the level it's been growing. So that's very positive. The other part of your question was other areas. I think we had 5 of our Western areas that we saw sequential growth in. And so we are seeing some turnaround in some of those areas. I would say the areas that probably we would expect to see growth -- had the most impact will probably be the Haynesville, the Eagle Ford and the Wamsutter area, particularly as we get into '18 on Wamsutter because there's a lot of activity going on in that basin that will turn that around as well. So -- but I think that's probably about the best explanation I can give you on that. So overall, though, I think we -- as we mentioned last quarter, we were seeing some of those areas bottom out and start to turn around, and that's exactly what happened.

And the next question comes from Colton Bean with Tudor, Pickering, Holt & Co.

I just wanted to check on the Geismar supply contracts. It was a little bit tough to parse out through the financials. Should we look for that to start up on July 6 with the commencement or the closing of the sale? And if so, can you guys quantify what the impact was there?

I do not have that number for you. I think you can call Brett or John to get a little more detail on that. But you are correct that, that actual contract would have started there upon the sale of that asset. So -- but bottom line, that plant is running well, and we're serving with ethane volumes. Obviously, a little choppy quarter because of the hurricane, and we did have some impact on the -- a couple of our pump stations on that system due to the hurricane. But overall, the relationship with NOVA is going very well, and providing them a lot of ethane.

Okay. I think you just alluded to kind of the 2018 plus outlook. But just in terms of the quarter-over-quarter step up on the processing side of things, is there a particular basin that really results in that, whether it's Niobrara, Piceance? Or was that more of a general uplift across the systems?

Well, yes. You named 2 of the areas that saw some of that uplift. And as well as I mentioned, looking broader, OVM obviously saw a pretty good step up as well, as the Southwestern volumes got added during the third quarter.

Okay. So for the Western segment processing volumes mostly, mostly those 2 in terms of Piceance...

Yes. We also saw WPX volumes in the San Juan Basin lift up a little bit as well. So we also saw some positive processing business from WPX's volumes raising in the San Juan Basin as well. So pretty well across the board, we saw a pretty good movement. Probably the one area that we didn't see much increase was in the Southwest Wyoming area, which is at our Opal facility.

And our next question comes from Shneur Gershuni with UBS.

I was just wondering if we can sort of talk -- I realize you haven't put out a 2018 guidance and so forth. But I was wondering if you can sort of talk about the board discussions with respect to returning capital to shareholders? You get to a point where your leverage gets in line to be able to do so. And I was wondering if you're looking at dividend increases at WMB? Or are you also considering potentially buybacks of WMB or even WPZ?

Let me have John Chandler take that, Shneur.

I think the answer is yes. I think we obviously are generating today around $100 million of the excess cash at WMB above our dividend. And as we look forward, we have about $300 million, I think, or $400 million on our revolver. So we'll continue to pay that down over the next several quarters. And then as we look towards our dividend growth in the future and the excess cash we'll have at the WMB level, I think our guidance is the same that we've given in the past that, yes, we'll look towards buying in WPZ units even perhaps coinvesting in projects if those opportunities existed, or buying in WMB or a dividend increase. All those things, I think, are on the table. We haven't carved any of those out. We, of course, are watching tax code changes too, and we don't expect that to happen until quite a distance in the future, as we think about dividend increases. That would kind of I think control what we did on the dividend front, but I don't think we've ruled out any of those options that you mentioned.

Okay, cool. And then just as a quick follow-up question, do you guys see an opportunity to expand Overland Pass, either on a small scale with pumps or something much larger in scale?

Yes. There's a lot of new production coming on, both in our Wamsutter area, in the Niobrara, both the Wyoming and DJ portion of the Niobrara, and of course the Bakken volumes that One Oak gathers as well. So a lot of incremental demand for NGL capacity out of the area. And if you add to that an expectation of that -- of the ethane market and demand market growing and expecting to have to pull on ethane from these regions, that today while they have ethane recovery capability, there's not ethane takeaway capacity out of the area because the NGL lines are cool. I think all of that leads to some expansion in the area. And certainly, Overland Pass is very well-positioned to capture that expansion. So yes, a lot of activity going on, on that front, and I think a lot of people are a bit surprised by the amount of volumes that are showing up coming out of these areas.

And the next question comes from Christine Cho with Barclays.

I actually just wanted to start with some clarification questions. In the West, all of the wet areas, with the exception of Opal, contributed to the increase in processing volumes?

Well, if you're -- I think we were talking earlier, Christine, we were talking sequentially.

Right, sequentially.

Yes. Let us provide some detail for you on that, Christine. I think the bottom line, we did see the Piceance pickup. We did -- we have seen the Niobrara picking up. And looking at kind of beginning the quarter and to end of the quarter, the pretty dramatic increase in the Northeast. As we mentioned, I realize your question is just to the West. But really, I think the majority of the increase is in the West, where a pretty moderate, in terms of processing volume (inaudible) with the exception of the Southwest Wyoming area.

Okay. And then with the compressor station coming on in Wyoming and the opportunities to work with 2 other producers, as you mentioned in prepared remarks, should we think that the G&P volume here like in the Rockies area is going to continue to increase? Or is it just going to may be stabilize, decline, so that it's flat? How should we think about that?

Well, if you're talking about overall West volumes, so if you're maybe just narrowing it to the Wamsutter area, we certainly expect some increase going into '18 there. And importantly, a lot of liquids volumes on both the condensate side, which we gather, as well as the gas and NGL side. There'll be quite a bit of growth there. If you broaden that question to the overall West, then I do think that we'll continue to see volume growth in the Haynesville, even though we're going to get up on the limitation of our capacity there pretty quickly in the Haynesville, and be looking for expansion opportunities on top of that. We're going to see the Eagle Ford continue to grow, and we are seeing growth in the Piceance as well and the Niobrara. Of course, that is offset by places like the Barnett and the Mid-Continent, and to a lesser degree, probably continued decline in the San Juan Basin as well. So I think that's the picture I would offer you there. But overall, I mean, Haynesville volume growth is very impressive. I wouldn't expect to see another 30% growth next year just because we're going to be so tapped out on capacity on our side. But we would expect growth from '17 to '18.

Okay, great. And then I don't know if there's much more you could provide. But on the Southwestern deal, can you just give some background on how that came together? Was that a little bit of a competitive process? Or did one of you approach the other? And can you give us an idea of how many more opportunities like that are still available?

Yes. Well, we have already have a very extensive relationship with Southwestern there. Because if you recall, that was -- a lot of that acreage was former Chesapeake acreage, and so we were already gathering a lot of that acreage, but we weren't processing it. And so because recall, Access didn't have a processing arm, and so that gas was gathered in the competitor's processing systems. And so our relationship with Southwestern that we've been working on, where we've reformed contracts out there and made them much more attractive contracts than what they had under the former Access Chesapeake arrangement that we announced earlier in the year, I would say, started that relationship off on the right foot. We also provide services to Southwestern up in Northeastern Pennsylvania, and we've been very successful there, helping them find excess capacity in that area as well. So I would tell you, our teams have worked really hard to have a very dependable and reliable relationship with Southwestern. And I would say they formed some contracts that are very aligned to both parties' interests. But it really spurred off of the fact that we had the opportunity to serve them and serve them well on the gathering side already, is really what enabled that relationship to expand.

Okay. Thanks for that. And then just last question. Overland Pass, can you remind us what the contract structure is there? Is that just based on a nomination basis?

You mean in terms of who gets curtailed and who doesn't?

Right. I just couldn't remember like when you guys started up that pipeline, if it was underpinned by some like level of MVCs or...

No, it's -- yes, it's a tariff contract, and so it has FERC tariffs on it and it has discounted rates from the original dedications that both One Oak and Williams enjoy in terms of the way the capacity is allocated. It looks back to prior periods to establish your allocation. So basically, build allocation capacity with your flow rates. And so whoever's been in it the longest with the most volumes (inaudible) longest has the capacity allocation.

And the next question comes from Danilo Juvane with BMO Capital Markets.

Just a few follow-up questions to what has already been asked. First in Overland Pass. My recollection was that to expand that system, you wouldn't really need pumps. It would be a loop of the pipeline because of how the pipeline is geographically located. Is that correct?

Generally, that is correct, Danilo. That's right. (inaudible) a little bit, but there's very little available. It's running pretty full already.

Do you have a sense, Alan, for what the investment opportunities could be for an expansion?

We haven't put that out there. And I would tell you, there's a variety of options that our teams are pursuing right now. So -- but it's a sizable investment. So -- but we haven't put (inaudible) on that.

And to the extent that would go forward here, you would still be able to self-fund your pro rata share of that growth?

Yes.

Okay. And as a follow-up, I guess, an extension of that question, financially, you seem to have a lot of optionality here. Schneur, I think, asked a question with respect to capital allocation. Beyond considering a dividend increase or buybacks, what are you guys thinking with respect to M&A?

I would just say, we've got such a great portfolio right now of high return investment opportunities that anything we do has got to peak with that. And so I think we are -- we've got our heads down very focused on developing the business that we do have. I would say that in areas like the Northeast, there is a lot of value in the consolidation of some of the joint ventures in the Northeast. And we continue to look at that as we have for quite some time, I would say. And we continue to have a bid-ask spread between us and the various partners up there. But ultimately, I think that's something that we would certainly like to see happen. But we're going to be very disciplined in what that CapEx investment is. So -- and I'd say that is very ripe in terms of that happening. We've got motivated sellers, and certainly, a lot of value in consolidation on our side, particularly in terms of the reduction of capital investment required to serve the growing volumes in the area.

And the next question comes from Eric Genco with Citi.

Just wanted to, just as a clarification, you talked about the buybacks and such. And you mentioned in your comments that you don't -- you're generating enough cash. You don't see yourself needing to access the equity markets, and that has been the case for '17. Is that something you foresee continuing into '18 and beyond? Or is that something -- is that too much of a stretch for right now?

No, that is exactly -- and we've said previously, we've said for the next several years. But I can tell you, in looking at our long-range planning, we don't see a need for that. So we think we've got a growth rate that's very sustainable with the combination of both retained capital and debt capacity, while maintaining some strong credit metrics. So feeling very good about capitalization right now, and continuing to fund the growth that we have in front of us.

That's great. And if I think about spending in terms of next year, I'm recognizing you may not want to give too much detail. But we've got basically the remainder of Atlantic Sunrise. We may see a startup of some of the Northeast supply enhancement CapEx. I would guess that's another big project. And then you had talked in the Analyst Day slides about a potential $500 million of annual growth capital in the Northeast. With the agreement with Southwestern Energy, is that something that -- is that something in the $500 million range next year, do you think? And how does that fall out? Is there a sense that you can give us as far as maybe a dip in CapEx? Or how that looks going into '18?

We're not providing guidance on that. But I would just tell you, what we provided at Analyst Day, both in terms of those continued opportunities as well as the opportunities in the Northeast, continue to be pretty in line with what we're seeing in terms of growth opportunities for the future. So kind of steady as she goes and no big surprises there. I will tell you that we're in a very nice position to be allocating to the very best capital opportunities, and we're maintaining very high returns as a result of that, and so we do have a whole lot of opportunities, but we're being pretty disciplined about what we're investing in.

And then I guess, lastly, I guess, in timeline, and maybe this is just sort of a theoretical question. But you mentioned about next year and how you're thinking about tax reform, and how that can impact some of your decisions. At some point, is there -- do you reach a point where you say, okay, we can wait on Washington, and see how they come out with tax reform? Or are there options at some point in terms of a timeline where you say we might want to take an action and we don't necessarily want to wait for full clarification from Washington on tax reform?

No. I think, in all cases, using tax code today and an amount of capital spend that we've got, we've got a fairly long window still of a period that we don't view that we'll have cash taxes (inaudible). I think we've got a long period that we can kind of wait to see this unfold. So hopefully, that answers -- we're not motivated to do anything quickly on that front.

And the next question comes from Shere Craig with Tuohy Brothers.

Alan, you talked about a number of incremental growth opportunities kind of in line with Analyst Day. Are you still seeing in total with what's already disclosed and what is kind of out there on the horizon, an aggregate sub 7x EBITDA multiple on all the pending projects out, say, through the end of the decade?

Yes. I would say the returns that we've talked about on Transco in that range, as well the very high return -- incremental return, I'm always quick to point out in the Northeast because we can't forget about the capital we had to invest to get those opportunities. But that is continuing to be the case in these regions, where we have very strong competitive advantages. So don't really see that changing all right now.

Great. And can you comment on the potential size and timing of additional West segment Wamsutter system expansion?

Yes. I would say the one -- the Chain Lake expansion that we did was relatively small. I think it was right around $50 million. And so I would tell you, the plans are getting bigger out there. For some of the players out there, the plans or their appetites are getting pretty big. And so we're watching that very closely, and we're beginning to plan alternatives with the producers out there in the area. So I do think there's going to be continued investments of probably that size and larger as we expand facility. But remember, we have a very large condensate handling business there already that can handle a lot of that. But we also have a lot of latent capacity at our Wamsutter processing plant. So just like in the Northeast, where we've got these high incremental returns, we're enjoying the same kind of thing in the Northeast because we have that latent capacity sitting there at our Echo Springs processing complex.

I know you all asked the FERC to kind of take some proactive steps on Constitution. Any updates there?

Continued great work by our team, Chad Zamarin, who's been heading up our efforts there with the federal agencies has had some very productive meetings, and continuing to push the ball forward on that. And so I would just say, stay tuned. We're -- pure upside to our plan, but we're encouraged by some of the commentary that we've got coming out of there. But still a (inaudible) when you're having to fight a stake as hard as we're going to have to fight that stake to win that battle. So plenty of fight left in this dog, and I think we're well-positioned for it. But we've got -- we will have a fight on our hand (inaudible).

Understood. In terms of timing to see how some of these steps kind of unfold, are you thinking that by first quarter, we can have more substantive detail?

Yes, I think that's a realistic timing, if not, before, to know kind of the next step there, anyway.

Great. And last question. Can you speak to the impact across your system from the recognizing of extremely nominal direct commodity exposures? But there's been much stronger propane pricing, and we're hearing word of ethane recovery just starting to kick in, in the fourth quarter here. Can you speak to the impact of those across your system?

Sure. On the propane pricing, I would say that we do have some pretty attractive hedges in place here for the fourth quarter. So we're -- and we've got a little bit going in, in the first quarter, propanes and some of our heavies. So I think we've got pretty good margins coming through on that. But as you know, it's just gotten to be such a relatively small piece of our overall business that's not all that big. On the ethane front, I think we have about 50,000 barrels a day that we could be recovering that is not unrecovered. But as I mentioned earlier, some of that is back behind pipelines that are constrained, like Overland Pass. Some of it is not, however, in the Gulf Coast. So we could see some pull through. In fact, we are seeing some ethane recovery. But I think the margin will just be as high as it needs to get to pull the ethane in until we see ethane get really short, which I think we could see. And then it's going to have to drive a margin high enough to pull in and build capacity on things like Overland Pass for those barrels. So I suspect that's going to take a little bit for the market to really realize it's going to have to pay up for that ethane before it comes on. So we'd expect some to and fro in the ethane market, as it tries to grab more capacity or (inaudible) up to capacity. So some exposure, but I would say we've got hedges on kind of in the mid-80 range on propanes here in the fourth quarter that will (inaudible) some of that dollar propane that you've seen it spike up to here and there.

Great. And just a final follow-on to that. More fundamentally, from a volumetric standpoint, subject of course to the de-bottlenecking process in the Northeast, are you starting to see increasing interest from investor customers -- or I'm sorry, producer customers in the wet gas Utica and Marcellus areas that could kind of feed that very long-term opportunity discussed at Analyst Day?

Yes. I think the areas that we're seeing right now is most focused on is the dry Marcellus, the dry Utica and the wet Marcellus. But probably, I would say in order of economics right now, because of the NGL lift that you mentioned just a while ago, we're seeing a lot of push into the wet Marcellus right now. And of course, the dry Marcellus is just such a terrific resource up in the Northeast that we're going to continue to see that area grab any kind of capacity it can just because the margins are so high on that. I would say the one area that we've seen pull back a little bit is the rich Utica is the one area -- or the wet Utica is the one area we've seen pull back a little bit relative to the other opportunities.

And our next question comes from Sharon Lui with Wells Fargo.

Just a follow-up on, I guess, the Southwestern contract. It sounds like you're using existing infrastructure to meet that contract right now. But do you think there is a potential to add, I guess, additional processing or frac capacity to meet that contract as volumes ramp?

I'm going to have Micheal Dunn take that one, Sharon.

At our Oak Grove facility, we currently have one TXP unit there, and a portion of a second one that was built a while back. So we have latent capacity in the first one that will be filled. And we do think the TXP-2 will be under construction sometime next year as well to handle that capacity. So there is some incremental CapEx there. But a portion of that has already been spent with the portion that was already built. So I would see certainly some capital expenditures contributed to that effort. Still capacity in some of our frac there. So I think we're okay for now on that, in that regard, but certainly, would expect to see some processing capacity expansion at Oak Grove next year.

Okay. And TPX-2 (sic) [TXP-2] is that another 200 ?

Volume? Yes.

Okay, okay, great. And just for the quarter, it looks like Northeast CapEx ramped up pretty significantly sequentially. Was there a specific project tied to that spending?

Yes. That's primarily some of the work we're doing for Southwestern with the agreement we had earlier this year. But the majority of it is for the Genesis expansion up in Northeast Pennsylvania to support Cabot in regard to their production that's coming online next year. So we would expect that to ramp up obviously in the fourth quarter, this year, as well, just finishing up that work. We've got a couple of compressor stations under construction there, as well as some pipeline interconnects and pipeline systems being built to support that expansion.

And our next question comes from Alex Kania with Wolfe Research.

Just -- I guess this question is in regard to the West and related to the asset impairment. I guess in the 10-Q, there's some discussion on a potential sale of some kind of assets in that segment. I was just wondering if you can give a little bit more color on that.

John, would you take that one?

Sure. I don't think we contemplate selling anything right now. We were approached, I guess, I should say, on some assets in that market that made us look at some tight curves again, and reevaluate the value of those Mid-Con assets. One comment I do want to make, the write-down was $1 billion write-down, but our -- our estimate of fair value does not change materially quarter-to-quarter for those assets. Those assets were actually written up. The book value of those assets were written up back in 2014 to 2015 timeframe when we acquired the Access assets, had a very different pricing environment, and of course, that's materially changed today. So actually, during the quarter, our fair value estimates for these assets have changed very insignificantly. What has changed is the overall view of discounted cash flows, and they fell a little bit below our carrying value that we had, the assets carried on for our books, which made us write them down to fair value. So I just want to make it clear, we don't have a change of view relative to the assets for the quarter that they changed by $1 billion. The (inaudible) cash flow just happen to fall below that book value during the quarter.

And we have no more questions at this time. I would like to turn the program back over to Alan.

Okay. Thank you very much. Thanks, everybody, for the great questions. Really excited to see the kind of top line growth that we saw this quarter from our retained businesses, and very excited about the growth opportunities that are in front of us right now. And look forward to a strong fourth quarter here as well as we continue to see the projects that we've been putting online continue to contribute. So thanks for joining us, and have a good day.

This does conclude today's program. Thank you for your participation. You may disconnect at any time.