威廉斯 (WMB) 2016 Q3 法說會逐字稿

Good day, everyone, and welcome to the Williams, Williams Partner third-quarter 2016 earnings conference call. Today's conference is being recorded.

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

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

Our CFO, Don Chappel, is available to respond to questions, and we also have five leaders of Williams operating areas with us -- Walter Bennett leads the West; John Dearborn leads NGL and Petchem Services; Rory Miller leads Atlantic Gulf; Bob Ferguson leads Central; and Jim Scheel leads the Northeast Gathering and Processing area.

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 reconcile to Generally Accepted Accounting Principles. These reconciliation schedules appear at the back of the Presentation materials.

We're planning on keeping our call to about an hour. If we miss any of your questions, feel free to follow-up with Investor Relations later on today.

And with that, I'll turn it over to Alan Armstrong.

Great. Well, thank you, John, and good morning, everyone. We're glad you've been able to join us this morning, and we look forward to discussing our third-quarter results here this morning.

As you can see from this quarter's results, our organization is firing on all cylinders, and it continues to capture opportunities as we execute against our proven natural gas-focused strategy. We're very confident about where we stand today, and our team is aligned and excited about all the great prospects we've got in front of us.

We've been taking decisive actions to enable steady predictable growth in our EBITDA by steadily increasing our fee-based revenues, lowering our costs, and positioning our portfolio of assets to capture growing natural gas volumes. We're making progress on many fronts as we work to execute on our strategy to drive predictable long-term sustainable growth.

We brought new projects online. We renegotiated some win-win contracts with Chesapeake, and expect to close on a new agreement in the Barnett soon. And we also completed the sale of our Canadian assets. And, as you are aware, we've also now kicked off a process for our Geismar assets. It's now -- that process is now in full swing.

On the cost savings front, since our cost reduction efforts were initiated at the end of the first quarter of this year, we've seen approximately $76 million of lower adjusted cost and expenses at WPZ versus the prior year. And that's all while continuing to add additional new projects and grow the business.

Specifically, we've seen WPZ's total cost and expenses decline from 55% of 2015 adjusted EBITDA to 47% in 2016 for the first nine months. So, an important metric that we're taking into account there, and continue to push that cost component down to a lower percentage of our overall adjusted EBITDA.

We continue to implement steps to further lower our costs by streamlining our organization. And, to date, headcount has been reduced by a little over 13% since the beginning of this year. So today, we'll walk through our results and provide some perspective on where we are relative to guidance and financial performance.

Our results here in the third quarter certainly validate the hard work of our teams across Williams. We'll also give an updated -- sorry -- we'll also provide some update on the Atlantic Sunrise project and highlight some of the key growth drivers that are now on the horizon.

So let's move on to slide 2. Here, as you can see, Williams Partners delivered net income of $326 million as measured by GAAP. And in terms of adjusted EBITDA, every segment of WPZ contributed to the 8% improvement over the third quarter of last year. Our DCF for the fourth quarter was $795 million, which was an increase of 5% over the third quarter of 2015.

As we've been doing consistently, we delivered fee-based revenue growth and we continued to benefit from the aggressive cost reduction activities we've been working on this year. We achieved a coverage ratio of 1.08% at WPZ for the quarter, which excludes the benefit of $150 million IDR waiver that was associated with the sale of our Canadian assets. And, as you all know, that sale was finalized, I believe, on September 23.

Overall, the quarter's results continue to demonstrate that our strategy is on the mark, so let's just touch briefly on a few of the operating areas. First of all, in the Atlantic Gulf. The Atlantic Gulf continues to deliver solid results as we put projects into service that are capturing more and more of the demand on the Transco system. Our adjusted EBITDA came in at $427 million for the quarter compared with $414 million for the third quarter of last year.

And, for the year, Atlantic Gulf's adjusted EBITDA increased $53 million, primarily -- sorry; so far, year-to-date -- primarily due to fee-based revenues from offshore operations and Transco's new expansion projects. The quarter also benefited from incremental volumes that came into our mobile base system from the Destin pipeline system, as we were providing service to volumes that were stranded behind Enterprise's Pascagoula processing plant.

We did see increased operating expenses related to pipeline testing activities as we continue to proactively focus on safety and regulatory programs along our Transco pipeline. Obviously, given the tremendous growth on the Transco system, we continue to focus on and ensure the safety and reliability of this critical piece of infrastructure. And so, solid results in the Atlantic Gulf. As we'll see later, lots of things coming down the pike to prepare for the tremendous growth in the sector of our business.

Moving on now to our Central, Northeast and West, I'd like to cover our nonregulated midstream set of businesses here, because we continue to see some common themes emerging across all of these operating areas. First of all, we have grown their adjusted EBITDA versus the prior year for both the quarter and also year-to-date. As you can see from the chart on this slide, Central is up about 7%; Northeast up 3%; and West up 3% on a quarter-to-quarter comparison.

All three of these businesses reported lower operating costs during the quarter. Our leaders and teams are very focused on preserving operational cash flows in today's slower supply growth environment. And we continue to see the benefits of that show up in our results. A

specific note about the Northeast -- because I know there's always a lot of extra interest in this particular area -- we continue to see steady to slightly increasing volumes there, but remains -- but this area remains in significant need of incremental takeaway capacity and market in the area. We believe that both the local and the national demand growth is going to really unlock the area over the next couple of years, but in the meantime, we're staying very focused on the cost-containment and achieving the best results for our customers.

Getting all of this critical new midstream in place as well has us positioned for when this tremendous low-cost resource really comes on in the next couple of years. And we really do believe that the natural gas demand that we're seeing on the Transco system will call on these constrained supplies once the infrastructure that connects that comes online. The unleashing of this resource and expected dramatic growth in the gathering volumes from this area represents tremendous upside beyond the more visible demand side growth that shows up in our CapEx.

On the NGL pet-chem side, we saw an increase in adjusted EBITDA, driven by higher olefins margins and strong operational production levels. Adjusted EBITDA for the quarter increased by $51 million to $136 million in the third quarter of 2015. And as I mentioned earlier, we also completed the sale of our Canadian assets, and we are off and running in a big way on our process to monetize Geismar.

This Geismar facility and the complex there really is a great asset, and we believe it's a good time to be in the market with the asset. There's a lot of very smart players in this segment, and a recognition of just how well-placed this efficient plant is in the Mississippi River market.

So let's move on now to Slide 3. As we've been saying, our natural gas-focused strategy is proving out and our year-to-date performance certainly validates that. Year-to-date through third quarter of this year, WPZ delivered $286 million net income and nearly $2.3 billion in DC up, up 8% over the same period of last year. And we also achieved a year-to-date coverage ratio of 1.04% at WPZ here so far in 2016.

I'm also pleased to report that we expect to exceed our 2016 adjusted EBITDA guidance, and also expect to hold coverage above 1.0% as measured for all of 2016, even with the expected seasonal increase in maintenance CapEx that we generally see in the fourth quarter.

As you can see, all of our operating areas are ahead of where they were a year ago, and you can see the results of our focus on increased fee-based revenues, cost reductions, and the full production and higher margins coming through at Geismar.

With that, let's move on to slide 4. This is a list of a lot of what's going on, and I'm not going to go through each of these items. But really the important thing is here's this long list of accomplishments that the team continues to execute on. And so this -- what's really impressive about this is all of the activity that we've got going on that's driving our growth for the future.

Just to mention a few here, highlight a few -- first of all, look at the number of projects that we began construction on in this quarter. And so Dalton, Hilloughby Phase I, the New York Bay expansion at Virginia Southside II. Our teams really have pushed through the permitting gauntlet on these projects, and are now really focused on safely constructing these important expansion projects.

We also have a number of projects that were already under construction. Moving down on the list, the Geismar process -- as I mentioned earlier, we have launched that process and we're3 really excited about the degree of interest we're seeing there.

And then, finally, on the coming soon part down there, just in addition to the -- all the projects that we've got going on, we are making a move to simplify our organization further here in 2017. And we're moving from five operating areas to three operating areas, which is going to enable some further cost reductions over and above those that we've captured here in 2016.

Moving on to Slide 5, a picture now of Atlantic Sunrise -- lots of questions, of course, coming out of the announcement from FERC that they were pushing back their approval by about two months. So, Atlantic Sunrise is a very key piece of energy infrastructure that is going to drive not just jobs in the Northeast and particularly Pennsylvania, but really the overall national economy, as these low-cost, very strong gas supplies here in the Northeast are going to enable manufacturing power generation and a lot of new trade around the world -- for markets around the world for our low-cost natural gas here in the US.

So, the Atlantic Sunrise system really does have a unique advantage in that it's one of the few of these major projects that takes advantage of the existing Transco infrastructure. And by building the segment that we have -- that's just the new pipeline in Pennsylvania, all contained within the state of Pennsylvania -- we're going to be able to reach markets in a very significant way, all the way into the Southeast markets where there's a lot of growing demand via coal conversion to natural gas power generation, the industrial markets. And, of course, the LNG facility at Cove Point there is an important market for those supplies as well.

So we announced on last Friday that we expect to begin a portion of service during the second half of 2017, and that we've revised the targeted full in-service date from mid-2018. I would note that, as we have previously, that our financial plan further risks the cash flows by approximately six months, and we've already adjusted our growth capital guidance to reflect this analysis.

We revised these dates because FERC now anticipates the completion date of the FDIS for Atlantic Sunrise will be pushed back to December 30th of 2016. This adjustment will allow more time for the Agency to complete a general conformity analysis and review two minor route alternatives. Additionally, we're focused on expediting the work required to obtain other key permits within the state of Pennsylvania.

To provide a little more context on this, the construction schedule on a project as large as Atlantic Sunrise is very tightly sequenced. Even a minor two-month delay on one aspect can have a ripple effect on other components of the project schedule, some of which are dependent upon lining up with the narrow environmental schedule.

So the good news is we've got about 96% of the survey work done. That means the landowners are cooperating with us in a way to get the survey work done, and we are -- we're pushing ahead to get the remaining 4% of that done. So, a lot of activity going on to get the survey work done.

Of course, if you think about the way these windows work -- the field survey work has to be done in a period where there's not any snow on the ground, and so that does put some risk into our schedule that obviously is the reason that we push some of this back. Because if we don't get those surveys done before snowfall -- and it certainly looks like that's not going to be the case -- then we've got to wait to get those final surveys done once we've seen things thaw out there.

So, that really is what's driving some of that scheduled pushback. So, again, it seems like a simple two months, but it does complicate things in terms of getting those surveys done in a timely manner.

I will say this about Atlantic Sunrise -- this is a situation where the regulatory agencies are being very cautious, given all the environmental opposition that has been focused around pipelines of late. We think that's prudent. And I will tell you that Governor Wolf has been very steadfast in his support for the project, and really all of the critical energy infrastructure projects in Pennsylvania.

And he continues to be clear in his support through that with his legislature and with other elected officials in the state. And we really do appreciate his cooperation, as he has a lot of issues to balance. But we certainly support the Governor in making sure that the resources are developed in a way that protects the environment and the health of the citizens. And we share his commitment, and look forward to our continued work with the PDEP there, which is the regulatory agency in Pennsylvania, to meet all these objectives.

So, feeling very good about the degree of cooperation and support that we're getting from the state of Pennsylvania, but it's just a matter of people being very cautious in the environment that we're operating.

With that, let's move on to Slide 6. You can see here the key growth drivers for 2017. Of course, the obvious stuff is the full-year impact of a lot of these projects that came on midyear, and then a lot of new projects that will be coming on in 2017 that you can see listed here. And then, of course, the -- a full year of cost reduction efforts will show up in 2017, as well as likely some additional contribution from the streamlining that I mentioned earlier.

Another consideration, of course, is just the impact that a normal winter would have on the Northeast local market demand for the regional consumption there in the Northeast. And so, if you think about that, there's two ways for gas to move out of those gathering systems in the Northeast.

One is the takeaway capacity -- we're certainly anxious to see the latest Rex expansion come on here towards the end of this year. But in addition to that, we also have the regional consumption. And with the very mild winter we had last year, we are hoping to see some incremental demand that would drive gathering volumes in the Northeast as well.

Moving on here to Slide 7, really excited about the strengthening of our Board and what's going on here within the third quarter, as we've added five new members to the Williams Board, and we're in the process of recruiting two additional members. The five new members are certainly energy industry experts, and each brings significant experience and have unique perspectives they are bringing to the table.

I can tell you firsthand that the new Directors, Steve Bergstrom, Steve Chazen, Peter Ragauss, Scott Sheffield, and Bill Spence, have hit the ground running and are very engaged in helping us maximize shareholder value. They are working with the rest of the highly qualified and independent Board to keep the management team accountable and focused on our execution, as that continues to deliver shareholder value.

I do want to take a moment here to just recognize three members of the Board who have chosen to not stand for reelection at our annual meeting in November in order to support our ongoing Board refreshment efforts -- and that is Joe Cleveland, John Hagg, Juanita Hinshaw. And really, all three have given tremendous service to Williams over the years they've been involved with us, and we are extremely grateful for their leadership, commitment to the Company and to our stockholders.

Williams stockholders can certainly be confident that this independent Board is working diligently on its behalf. And we, as a management team, are really excited about that.

With that, we'll move on to Slide 8. So, today, the premier natural gas asset base in the nation is delivering fee-based revenue that amounts to about 93% of WPZ's gross margin. There's tremendous demand growth occurring and continuing to come down the pike. And Transco is the energy lifeline that physically connects Williams to that growth.

The team has delivered continuous growth and the third quarter of 2016 is no exception. We believe that the natural gas-focused strategy that we're executing on has us exactly where we need to be today and well-positioned for a large degree of upside in the future, as the natural gas market grows on the backs of this very low-cost resource base. And we'll really draw on the Northeast and drive strong growth in our volumes in the Northeast as that occurs.

We're continuing to capture fee-based opportunities. We're reinvesting in Williams Partners, and we've taken swift decisive actions to strengthen the balance sheet, reduce risk, and focus on driving shareholder value.

So, once again, we thank you very much for joining us today. And with that, let's move on to questions.

(Operator Instructions) T.J. Schultz, RBC Capital Markets.

Maybe if I can just start with Geismar. Just any color at this point on your bent toward an outright sale or to try to convert to a tolling structure. And then if you could just discuss what type of counterparties you are engaging with under each scenario? That may be helpful too. Thanks.

Sure. Thank you very much for the question. You know, we remain open. We're going to look to whatever the best value is in terms of those two opportunities. I would say on the sales side, of course, it's going to be a party that we're confident that can close the transaction swiftly and puts the very best value proposition on the table.

As to the tolling arrangement, a little more dependent on the personal nature there, because it'd be somebody we would be involved with for the long-term. And of course it would have to be somebody with strong credit to stand behind the obligations, the tolling agreement. So, I would just say we remain open to both, but we'll have to see what the best value comes through there.

I will say a really long and large list of parties engaging with us on that. And we're really excited to see the way that asset is positioned in the market right now.

Okay. Great, thanks. I guess just one more on Atlantic Sunrise, with that pushed out, kind of two parts. I guess, first, with that risk I think in your financial plan by six months, do you essentially have that full service in your plan for the beginning of 2019?

And then the second part, just given that timeline, or even if we assume it comes online in mid-2018, I guess the question is just really around the DRIP or more WMB support. Does that change the timing or how long or what degree you would need to keep participating? Or is there any other support you may need in 2018 as you are kind of keeping that IG rating at WPZ?

Yes, great. Thank you very much for the question. I'll take the first part of that and I'll turn the second half over there to Don for the financial side of that.

In terms of the schedule, I think a couple of key things that are coming through in the change to the schedule. First of all, really excited to be announcing that we're going to be able to bring on the mainline portion of that project, which is obviously really important in the Northeast to take gas out of the Northeast down into the Southeast markets. And we'll be able to do that in the second half of 2017. So that's pretty exciting.

Then there's another section that we likely would be able to bring on, which would be the pipeline -- the new pipeline itself, that would come on second and -- as soon as it's constructed, would come on second.

And then finally -- and this is where that final date that we talk about -- would be the compressor stations that are on the new pipeline, not the existing but brand-new compressor stations, that would come on to add some incremental volume to the project. And that part would come on six months after the mid-2018. So whether you want to call that end of 2018 or first part of 2019, it's kind of splitting hairs a little bit there perhaps. But that is what our expectations are.

But I think very important is the amount of volumes that we can bring on with the first section coming online in the second half of 2017. And then later the pipeline section that would be carrying gas out of Susquehanna County and Bradford County areas. And that would be coming on ahead of that final section, which would be -- in our Risk Financial segment, would be either very end of 2018.

And so, I think in terms of the -- clarifying that, our team is very focused on bringing this mid-2018 date to reality. And -- but we, as always, we put further financial risk into our plan to allow for all the regulatory uncertainties that all of us in the pipeline industry are facing these days.

So, with that, I'll turn it over to Don to talk about the financing side.

Sure. Thanks, Alan. Certainly, the target date change, or our financial plan date change related to ASR, reduces the 2017 CapEx and related financing needs somewhat. We're not making any, I'll call it, formal change in our financing plans at this point, as we continue to drive our credit metrics up or improve -- I'll say it that way -- in an effort to ensure that we have strong credit metrics, we get credit from the agencies, and we continue to delever WPZ and WMB.

But nonetheless the fact that there's less of a bubble in 2017 I think is helpful in terms of 2017's financing plan. But I think, as you point out, it does push some of the capital into 2018. As to how we'll finance that, we're not compared to prepared to provide any guidance on that today.

Okay. Thank you, guys.

Thanks.

Brandon Blossman, Tudor, Pickering, Holt & Co.

Just a quick follow-up on Atlantic Sunrise. So, I guess one, it's imperative to say that the vast majority of the permitting and regulatory risk resides with the greenfield portion of the pipe and not the new compression stations on the mainline, is that correct?

That is correct. And just to be clear, most of the work on the mainline is just turning. And for those involved with the project, they'll scold me on this when I say just -- but it's a matter of redoing a lot of the station piping on those existing compressor sites that is required for that second half of 2017 in service for the mainline.

And then as we think about a second half 2018 and service for the mainline reversals, how should we think about EBITDA associated with that, in terms of contracts or counterparties? And who can actually flow on that portion of the line?

Yes. Of course, we'll be working through that. I will tell you that we've seen a lot of strong interest and people have started to acknowledge that that likely would occur. And that's what we've done in the past as well. When we've had projects come on that have involved mainline, we've opened up that capacity as it's been made available.

So we don't have any specifics on that yet in terms of how much that EBITDA would be, but it will allow for some pretty significant flows to the South coming out of the Southeast Pennsylvania -- the mainline in the Southeast Pennsylvania area there. So, other big interconnects coming off of other pipelines will now have a way south.

And I think if you think about how the demand would look, all you would need to look at is Zone 6 on Transco versus the Southeast market -- see that differential there, and you would see the amount of demand that would be available for that capacity. So we're not going to pin that down yet because we haven't finalized the negotiations for that, but it is -- obviously there's plenty of demand for that service.

Thanks, Alan. And then switching gears back to Geismar, obviously a very good quarter, Q3. Last-quarter Q2, you had said or mentioned that, at least to some degree, you were holding back inventory to sell into Q3 on expectations of better margins. Obviously, you got that. Just in terms of capacity factors in quarter for Geismar and inventory levels, are thinking about anything like that again for Q4 in terms of holding back some production?

I'll turn that to John Dearborn, who is on the line with us.

Yes. Thanks, Brandon, and thanks for your interest in Geismar. Geismar has been running extraordinarily well -- very reliably. And we're really pleased to be able to deliver ethylene again reliably to the market. And we've proven that out now for a year.

As to your specific question about inventory, we came out of the first quarter with about 30 million pounds of inventory. We sold some -- we sold our full production during this past quarter. We've held some inventory coming through this quarter with an expectation that -- we pushed that expectation out into the fourth quarter, because we still do have a belief that some of these crackers that have been challenged in the third quarter will remain to be challenged in the fourth. And we may still see some better margins.

So we actually, coming through the third quarter, built a little bit of inventory here on hopes that now the fourth quarter is going to give us a little bit of a better return on that.

Perfect. Thank you, John. Great color. That's it for me.

Thank you.

Thank you, Brandon.

Ted Durbin, Goldman Sachs.

Maybe just on the earnings, if I could start with Atlantic Gulf. You had a big step-up in your nonregulated fee revenues versus what you did in the second quarter of 2016. I'm just trying to figure out the drivers there. Is this the new run rate?

And then I think you mentioned you got more volumes on Destin as well because of Pascagoula being down. Maybe you can give us a number there on how much that impacted you?

Sure. Thank you for the question. Certainly the big driver for second versus third quarter and 3Q was the -- having both the Tubular Bells business online -- and remember that had 30 days of shut-in in the second quarter, as we tied in -- as we did some of the work for the tying-in on Gunflint during the second quarter. So the second quarter was abnormally low because of that big shut-in.

But here in the third quarter, the -- both Kodiak, Gunflint and Tubular Bells were all producing. And so some improvements are going on out there. In fact, we're -- we've completed the mechanical completion on the second phase of the Gunflint capacity out there, so a lot of important work still going on out there in terms of enabling further flows. So that was a big driver.

But then, as we did mention the Pascagoula plant was down, and our team went to work very quickly to make some big offshore interconnect in, I think, the July time frame, June and July time frame, that enabled us to bring that gas in very quickly. So, great work on the team's part of getting that work -- first getting it permitted, and then very quickly bringing it on.

So that didn't just fall in our laps. It was great work on the team's part to get that in.

We expect that -- I think Enterprise has said they expect to start bringing Pascagoula back up in December now. And so we would expect to get a couple of months in now here in the fourth quarter from that.

And in terms of impact, I don't think we specifically said how much that was, but you can see some of the impact to our volume. I think it was about [200 million] a day, maybe [210 million] of volume that's come into the system from that, just to get an idea of what that's done to gathering volumes in the Eastern Gulf.

And Alan, some of that shows up in fee revenues. Some of that shows up in liquids margin as well. So it's not all impacting fee revenue. I might just point that out.

Thanks, Don.

That's very helpful. Thank you. And then if we can just talk through your new Barnett gathering agreement, the -- some of the parameters or assumptions you are making to get to that $240 million loss of undiscounted cash flows, I think you put in the press release.

Are there volume assumptions behind that? Can you quantify what percentage of Henry Hub the new gathering agreement is at? Maybe what other things we should be thinking about in terms of rig count or whatnot to get to that number?

Yes, let me have Bob Ferguson take that, please.

Yes. Let me just kind of recap what we've done -- is, right, we traded the minimum volume commitment numbers for, in essence, a percentage of Nymex contract. For competitive reasons, we're not ready to say what percentage of Nymex that is, but it's set to, in fact, hopefully incent the drill bit.

In addition we have contractual obligations for the producer there to spend certain amounts of money on drilling and recompletion work during the next two years of the contract. So we're anticipating that we'll at least lessen the decline, maybe even get some pickup, depending on what the completion technology does today. And it's really the cash difference that we indicated, was the difference between that absolutely no MBC and what our projected volume and revenue difference was during the period through mid-2019 when the MBCs ended.

On a present value basis, we picked that up and it's at present value neutral transaction to us. But we did have a slight cash difference in the next two years.

And this is Don. I'll just add that the price assumption that we had, I think when we put out the disclosure, was basically forward strip prices at the time, and a modest amount of arresting of the decline. So again, the drilling that Bob described would slow the decline somewhat.

That's great. And then just a follow-up on Atlantic Sunrise. So are you in a position where you can tell us the amount of volume you'll actually move on these -- sounds like three phases, the mainline, and then the new pipeline, and then the compression? Or are you still working through that?

Yes, we are. So we haven't detailed that out yet. We are working on that. I would tell you that, of course, the mainline, we'll the prepared for moving all of the volumes out of the project, but it's got to have deliveries from the North, pressures from the North, to be able to do that.

So that will be somewhat dependent on what comes in from other interconnects in terms of really getting down to a specific volume coming from the Northeast. So, said another way, it's not going to be finite, because we don't know exactly what the other interconnects are capable of delivering into that.

Secondly, the pipeline portion -- let's call the Central Penn, and I believe it's referred to as North Central Penn coming out of Susquehanna County -- that pipeline will be capable of delivering a very large portion of the volumes from the North without the compression during most of the year. And so, in other words, it's depending on other operating conditions on the pipeline, but it will be a very substantial portion of the available volumes from the North.

Okay. But you're not upsizing the -- in other words, the 1.7 dekatherms a day, I think -- that's still constant?

That is correct. That's right.

All right. That's it for me. Thank you.

Thank you.

Shneur Gershuni, UBS.

Just a couple of quick clarifications to some of your earlier responses. When you had said that there was a lot of interest in Geismar, does that mean that the data room is now open and people have actually expressed interest formally? Or is it just more in conversations?

No, the former. We have opened that and we are in the process of getting all the NDRs resolved, but that process has officially kicked off.

Okay, great. And then in some of your responses about the Atlantic Gulf performance, I was wondering if I can ask a question a different way? Is the level of EBITDA generation this quarter, is that your full -- does that fully reflect the run rate for the new plants that came online with Kodiak and so forth? Or is there a little bit more to step-up there as well too?

Yes, you know we always hate to get ahead of the producers and their announcements of volumes out there, but I would tell you I think Hess has been pretty clear that they've been doing some rework on their wells out there on the Tubular Bells field. And as well, as I've mentioned earlier, we did, in the quarter, complete to the mechanical completion part for the Phase II of Gunflint -- for Gunflint, which allows additional capacity for both Gunflint and Tubular Bells out there. So, we would expect to see some improved volumes coming on here into the fourth quarter and first quarter of next year from those prospects.

Okay. And one last final question. Alan, you guys have been fairly successful in bringing down costs for over a year at this stage right now, if I sort of think about it. Your headcount is down 13%, I think you said earlier in the call. Should we think about this kind of level of O&M and SG&A as kind of the go-forward rate? Or do you see incremental opportunities to bring down costs further on a go-forward basis? How should we think about this sequentially, I guess is my question?

Thank you. First of all, I'll talk about kind of the two issues that balance that. First of all, on the overhead and management side, our team is very committed to continued pressure against the overhead cost side of our business, as well as your direct operating expense.

You know when you go into an area, for instance, like the Northeast, and you are rapidly growing things, it's very hard to really streamline your operations and really focus on cost reduction at the same time you are trying to build up the staff, train people and get your operations safe and reliable.

And so that -- at that business, as its gained its scale and its footprint is very well-positioned now to really take out some costs, likewise our Central area has just done a tremendous job there. Because if you think about the pattern of growth and buildout that had gone there for several years, that has slowed down in terms of that pattern of buildout. And so the team has -- management team has done a great job of redirecting their focus as a management team on safe and reliable, and even more cost-efficient operations.

And, of course, out West, that team has taken that on kind of as their mantra. And they're very, very focused on constantly lowering their unit costs. So that's really driving a lot of that in terms of the cost reduction. I do think it's sustainable on the one hand.

On the other hand, I would tell you that, as we go into the pipeline operations, a lot of need to make sure that these pipelines are maintained extremely well. And I always tell people I think that's a really terrible place to try to save money, is in the place of doing a great job of maintaining your assets safely, and particularly in these critical areas along the Transco and Northwest pipeline and Gulfstream routes.

And so that's an area that I think, as you've seen a little bit in this quarter, we had a lot of hydro-testing and repairs on Leidy systems. And, quite frankly, we're not going to shy away from improving the system there whenever we have an opportunity to do that. And so that's the cost side that will probably continue to pressure us up on the one side. But I think on the cost efficiency side in overall day-to-day costs, we'll continue to have opportunities to push that down.

Cool. All right, Alan. Thank you very much. I really appreciate the color.

Thank you.

Faisel Khan, Citi.

Just a few questions. First on the balance sheet, you guys are clipping away at your revolving or debt balance at the WMD level -- looks like $260 million a quarter. How long -- I guess what's the game plan for the paydown of debt at the MB level? How far do you want to take that debt level down?

Faisel, this is Don. I think the amount that we're able to take it down in the quarter was aided by the Canadian proceeds. So we don't see that same opportunity over the next several quarters. We do have a plan to, I would say, that continue to chip away at the Williams debt, but it will be at a modest pace for the foreseeable future.

Okay. Got you. And then the $250 million investment in WPZ common units, were there any other third parties that participated in that placement?

That was a private placement that wasn't offered to any third parties. We'll take a look at what the DRIP program that will be upcoming here in the very near future, we'll see what that holds.

Okay. And then on the cost of the Sunrise project, was there any change in the cost, given the slight pushback in the timeline?

No, we still are maintaining our cost targets on that front.

Okay. And then if I look at -- going back to your, Alan, your comments around the volumes that will come online in the second half -- so is it fair to say that on the Leidy southeast line, which is, I guess, half a BCF a day, that you'll be able to flow that entire volume down south in the second half of 2017? Is that -- I think that's what I was trying to figure out if you were getting towards, but maybe I got it wrong.

Yes, it's kind of hard to know exactly who will take that space on the mainline. So anybody that's got gas trapped in Zone 6 that can get into the system. So you have -- of course you have the big Texas Eastern T-MAX project that connects just north of this point. And so, there's a lot of -- or sorry, the expansion goes just north of that point. So there's lots of big interconnects like that, that could supply gas into this.

And it will just be a question of who wants to -- where the gas is the cheapest, I suspect, as to where whoever takes that capacity and utilizes that capacity, which would likely be the existing holders of the capacity for the full project, I suspect that given how in the money that will be, I would be surprised if they don't take that. And if they do, it's just going to be a matter of where they buy the cheapest gas in the area to move it South.

And then just how far south will they have to move it? I guess from Station 210 or 195, how far south will you be able to move it in the second half of 2017?

Yes. So that will be the full expansion. That goes all the way to Station 85 at its further extent. And, of course, one of the big delivery points there is to the Cove Point delivery point, is one of the big takeaways for that. But the capacity kind of, as designed, goes all the way to Station 85.

Okay. Got you. And last question will be -- just on the MBC, in the quarter -- I mean, I guess if I look at the adjustments or the add-backs, that add-back is a cash item or a non-cash item that's being actually added to adjusted EBITDA?

Faisel, in the quarter, that's a non-cash item, so it's a -- I'll call it a contractually expected MBC. Now that will all be settled as we close the Barnett transaction with that $754 million payment.

Okay. Got you. Great. Thanks, guys.

Darren Horowitz, Raymond James.

Alan, considering the currently expected Northeast takeaway project and service dates across the board on the east side of the Marcellus and Utica, what impact do you think that's going to have on basis differentials over the next few quarters? Specifically Dominion South, TETCO M2 versus Henry Hub?

And more importantly, how do you think the Northeast market gets further rationalized, regarding the amount of market pipe capacity versus that big growing magnitude of supply growth that's waiting on pipe to get out of the basin?

Yes. You know, I think that's such a complex issue because it's very dependent on where the gas is, it's very dependent on what outlet markets each of that gathering volumes, I would say. Some of the big players that have done a great job -- and I would include Cabot in that group that have done a great job of going out and finding incremental markets, whether it's local power generation that's coming on, and have really used their scale to go out aggressively and capture some of those markets, will be the parties that are advantaged.

And so this isn't the first time we, as an industry, have seen something like this. We saw this in the Rockies back when we had $2.75 basis differential, and it worked itself out over time. People started to think it was never going to come over that barrier. And today, we sit there with basis differentials of around 5% or often less in the Rockies today.

So I think we'll eventually get there, but it is a complex question, just given all the number of projects that are coming on, and the interconnectivity of the pipelines, to be able to address that. So I would say I think the Southwest markets probably are going to be picking up, hopefully, the Rex expansion here in the very near future, which will be helpful to that area.

And then I think Atlantic Sunrise will be the next big adder to that area as we unload all that gas trapped up in Zone 6 on Transco with those projects coming online. And I do think that will -- to your question -- I do think that Atlantic Sunrise coming on will improve the Dominion South basis just because you've got so much capacity between coming over on the Tmax project, that will have a chance to move south as well, that's pretty well trapped up there in that Zone 6 area today.

So I think it's going to take time for all these projects to come on, but I do think that we will see that basis collapse pretty substantially as we get into 2018.

Okay. And then as a follow-up, just quickly on the discussion around Zone 6 on Transco, thinking about, as you mentioned, all that gas trapped behind the pipe. Over the next few quarters, what do you think that means for potential IT opportunities, either backhaul initiatives or better economics, or maybe just incremental EBITDA pullthrough from walk-up shippers that are trying to -- or bases? How do you think that plays out specifically for Northeast G&P profitability over the next couple of quarters?

Yes. I think the market will continue to take advantage any time there is any little opportunity. And I would tell you I think the market has been in this situation long enough now up there, it's probably rooted out most of the easy stuff in terms of a little IT. Now Transco is a good example of that, where we've had Leidy limited on capacity here for most of the summer. And that just got released.

And so that was held back because we had some pressure limitations on that pipeline that we were -- we needed to do some inspection before we returned to full pressure. We've done that. And so, that's a big -- will be a positive in terms of incremental volumes out of the area.

I actually think the biggest driver for incremental volumes out of the area is going to be the local load, as we have a -- hopefully, have a more normal winter in the Northeast. That's actually going to allow for the local load to absorb some of that gas. And if that occurs, there will be some incremental IT opportunities on days when we could move more volumes out of the system, because we've got good pressures and good load in the area. So, I think that's what you -- probably the biggest driver for incremental IT is probably local load in the basin.

Thank you.

Thanks.

[Denore Giovane], BMO Capital Markets.

Most of my questions has been hit. I had one quick follow-up on Geismar as you sort of further the strategic alternatives here. Do you have a sense for when you will choose to go either way with a toll or a sale?

Again, it would be some time when we see all the bids in the door, but I would expect that would be towards the end of the first quarter probably before we would know which way we were going on that.

Okay. No, that's it for me. Thank you.

Thank you.

Sharon Lui, Wells Fargo.

I was wondering if you could touch on, I guess, the new G&P contract in the Powder River Basin and the potential impact on cash flow, as well as any discussions about recontracting in the Eagle Ford with Chesapeake?

Yes, sure. I'll take the Eagle Ford question and I'll let Walt Bennett take the Niobrara question. On the Eagle Ford, I would just say that there's a lot of talk about that, but I think from our perspective, we're pretty happy with where we sit there. And we think that there's good business to be had by increasing volumes in there, which will of course serve to lower the rate just through lower volumes.

And so there may be some opportunity as we found in other areas or maybe some opportunities for marginal improvement there, but I think from our perspective, we like the business out there and are anxious to see Chesapeake continue to be more and more successful, as they have been in their technical accomplishments out there. And so we're excited to continue to work with them to see those volumes expand.

And I'll turn the Niobrara question back to Walt.

Sure. Thank you, Alan. So the Niobrara contract that we have agreement of terms on now and we're working to finalize that into a definitive agreement. The way to think about that is that that will keep EBITDA near-term pretty steady for that gathering and processing system.

And what we did in the agreement with Chesapeake is it really aligned both the interests of Chesapeake and Jackalope, which is the JV between Williams and Crestwood, to make sure that it was incenting development of some of the other formations there. So we got dedication of additional formations that we didn't have previously, and it allows Chesapeake to go out and explore those economically, and see what the upside may be.

So, as I said, it will be pretty consistent for EBITDA in the near-term, and then there's definitely potential longer-term, as those new zones get explored and, hopefully, Chesapeake is very successful with that.

Great. Thanks, Walt.

And just another question in terms of guidance. Given the strong quarter as well as your project updates, any change in 2016 guidance as well as your leverage targets and potential distribution growth targets for 2018?

Yes. No, we haven't put anything out beyond 2016. And as I mentioned in my comments, we do expect to exceed the earlier guidance that we put out for 2016, but we haven't put a specific number on that. I think the -- our business, if you look at how steady we've been in growing the business, I think it's fairly predictable here as we go in, within a fairly tight range as we go into 2016 -- or sorry, as we end 2016. But we certainly expect to beat the earlier guidance for 2016.

And we'll be making some decisions about when we announce the 2017 number, but certainly would intend to do that by the time we announce the fourth-quarter -- either at the time we announce fourth-quarter results or before that for 2017. So, that's about all we have to offer on that.

Thank you.

Thank you.

Craig Shere, Tuohy Brothers.

Thanks for squeezing me in. On Geismar -- and I appreciate the update on the timing on that -- if you did go opt for a sale versus long-term tolling, how do you envision the impact on the DRIP with that? Could you materially reduce the amount of equity being raised through 2017?

Craig, this is Don. I think it would depend on the sales price, and we would likely have a conversation with the ratings agencies as well. So, obviously, you are going to lose EBITDA in the process. But qualitatively, the EBITDA is margin EBITDA, so just depending on where margins are. So I think that will be something we'll decide once we see what the numbers look like from the process, and then take a look at what we think that means and have conversation with the agencies.

Well, on that note, Don, obviously, given your enterprise multiple, a Geismar sale would be cash flow dilutive, but nobody is going to give those cash flows, based on margins, the same kind of credit that they would all these fee-based projects you're bringing on over the next couple of years, that could be being built at similar multiples. So, how much credit do you see the rating agencies giving you in terms of just derisking the business for the Geismar sale?

Craig, I think that's unknown at this point, so I think that will be dependent on kind of where margins are and really the rating agency point of view. So you will have to stay tuned for that. I think that's something that we'll know as we get closer to the end of the first quarter.

Okay. And the last question -- any updates on the broader industry M&A process?

Craig, no updates on that. I will say in terms of your prior question, we'll be down to around, I think, 2.5% of our business. If we execute on a Geismar sale as well as a Canadian sale, we'll be down to around 2.5% of our gross margin coming from direct commodity margins. And so we would expect that certainly deserves some attention by the rating agencies. And so I appreciate you pointing that out. But no, I don't -- we don't have any updates on the broader M&A picture.

Thank you.

Becca Followill, US Capital Advisors.

Just back on Atlantic Sunrise. Can you -- I know you talked a little bit about volumes. Can you talk about when you start getting paid when the contracts kick in on those -- on the project? Does it wait until the entire thing is done, or at least the portion that's without the compression in Pennsylvania?

No, Becca, the way that would work is that -- and as we've done in past situations there, it would just be putting capacity early in service, and people could elect, if they chose to, to pay the full contracted rate for the project to -- for that portion of the service that's made available early. So, that's the way that works.

So you're saying that you wouldn't get the contracted volumes until mid-2018? And it would be IT in the interim?

No, it would -- the same service would be made available -- of course, that goes through a FERC process, just to be very clear. So it's kind of not prudent for us to predict exactly how the FERC would do. But in previous situations, we've been able to sell that service for whoever wants to take that firm available capacity in the earliest, since they have a limited service date. They don't have the full extent of the service available to them. Again, that is subject to the FERC's determination on that, as we would apply to put portions in service early.

And then can you clarify, in the Pennsylvania portion of the line, how much capacity the compression adds?

That's very determined by the pressures on the downstream system and when the system is operating full design pressure. If the system is -- has -- is operating at normal operating conditions, it would be pretty substantial in getting up near 80% to 90% of the volumes. And on the low normal days, even higher than that without that compression.

I think I'll follow up, because I'm unclear on that answer. And then do you have any -- how much volumes are shut in on your system in the Northeast in Q3?

No, we're not providing that this quarter. And mostly just because we -- our customers have not wanted us to be advertising what that is for the benefits of their markets, and we certainly want to be respectful of that.

The -- I will say, Becca, on your earlier question, it's simply a matter that you have a pipeline in service; the compression is designed to make sure that you can have adequate pressures on the system and deliver at full design situations. So when the pipeline does go into service, but you may not be at full peak design demands on the system, obviously you can move more gas when you are off-peak.

And so, that's the reason that's not a simple question, because it's very dependent on what the operating conditions are on the pipeline at the time.

Okay. Thank you.

Thanks.

And that does conclude today's question-and-answer session. At this time, I'd like to turn the conference back to Alan for any additional closing remarks.

Okay. Well, great. Well, thank you all very much. I do have one thing to add here -- just some congratulations to our team that has been working so hard to gain closure on the Barnett transaction with Total. So we do have a new large customer there in the Barnett in Total, as that has closed here this morning.

And so, congratulations to our team that has worked so hard to get that closed. And we're excited to be working with Total to improve their returns and volumes on that system.

So, thank you all very much for joining us, and look forward to speaking to you in the fourth quarter. Good bye.

Again, that does conclude today's presentation. We thank you for your participation.