Good day, everyone, and welcome to The Williams Fourth Quarter and Full Year 2018 Earnings Conference Call. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations, and please go ahead, sir.

Thanks, Amy. Good morning, and thank you for your interest in The Williams Companies. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include press releases and related investor materials, including the slide deck that our President and CEO, Alan Armstrong, will speak to you momentarily. Joining us today is our Chief Operating Officer, Micheal Dunn; our CFO, John Chandler; and our Senior Vice President of Corporate Strategic Development, Chad Zamarin is with us as well. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks and you should review it. Also included in our presentation materials are various non-GAAP measures that we've reconciled to Generally Accepted Accounting Principles. And these reconciliation schedules appear at the back of today's presentation materials. And so with that, I'll turn it over to Alan Armstrong.

Great. Good morning, everyone. Thank you, John. I'm going to start a little bit with the macro conditions that continue to support our strategy so well. So if you think about our continued focus on natural gas demand and how that's driving our strategy and you look at actually what's occurring, we really saw it start to accelerate in '18 as we saw an 11% increase in overall natural gas demand. And as I'll remind you, that's on top of a big demand that we had in '17 as well and we also have another expected 5% increase by most of the forecasters now for North America, so demand growth on top of demand growth on top of demand growth. But if I put that in perspective for you, it really is starting to -- what is happened is -- what we expected to happen, which is not just the U.S. but all of the world is really starting to try to take advantage of the U.S.'s ability to get gas out of the ground at such a low cost. So just to think about that 11% increase that we had this year, I think it's helpful to put that in perspective and something we can all relate to and that is that 11% increase was greater than all of the dry gas production from the Permian in 2018. So just here in one year, we've had an increase that's greater than all of the dry gas production coming out of the Permian today. So the demand growth is very important to our strategy and we continue to see that be very supportive. So with this backdrop, I'm happy to report that our portfolio of indispensable natural gas infrastructure performed even better than expected this past year as we once…

[Operator Instructions]. And we'll take our first question from Shneur Gershuni of UBS.

Just wanted to start off on the new project that you announced last night. On a go-forward basis, do you expect to aggregate more barrels? And could you see a need for a greater than 20% stake in a frac? And also with -- any sense on what the stack rate would be to get the Y-Grade all the way to Mont Belvieu?

I would say, first of all, on the volume growth, yes, we did build in the flexibility in our relationship with Targa to be able to expand our volumes as we need to, both on transport capacity as well as on the investment in the fractionator. So -- and I would say that we definitely are seeing a lot of opportunity to continue to pick up new barrels out of both the DJ and the Rockies. And so we're pretty excited about that. And obviously, we like the fact that Conway becomes an important center now as we open that up to new markets, so we're pretty excited about that alternative. And then on the -- I would just say on the rate, we're not going to disclose that. But I would say it's very competitive and we're very excited about it, about the way that rate is structured. And again, I think Targa saw this as a long-term strategic relationship with us, and likewise. And so we see this as a great opportunity to maximize the combination of our assets at Conway and Bellevue.

That makes sense. And given your new partnership with Targa, do you see an opportunity to expand the relationship with respect to gas takeaway out of the Permian, given that both companies have been exploring different gas takeaway solution?

Yes, this is Chad Zamarin. I would just say that we continue to -- I think if you look at our recent announcement with the Brazos Midstream system in the Permian, we continue to focus on the Permian. And I would just say, we're going to continue to be disciplined and there have been two projects that have been announced coming out of the Permian to move gas to the Gulf Coast, but we continue to look at options. The Brazos system provides us much like the move that we made into the DJ and the ability to move downstream from that position. The Brazos system provides us with an opportunity to continue to develop projects that we moved to the Gulf Coast. And I would say that we are likely, if we do move forward with the project of that sort, to partner with others in order to make it a most efficient project. So we continue to work in that manner.

Great. And one final question. When I think about your CapEx guidance for 2019, I know it technically goes up from the prior guidance. But when I think about it on an apples-to-apples basis, you have some rollover from 2018 into 2019. And you've just announced new project, so it would kind of seem like, on an apples-to-apples basis, your CapEx is actually declining versus prior expectations. Can you give us a little bit of color around that? Is it cost related? Is it due to some of the asset sales? Just trying to understand these subtle changes.

Yes. I would just say, first of all, most importantly, the Bluestem -- most of that capital for Bluestem will be spent in 2020. So that's primarily why you're not seeing less driver in that. So it's not -- frankly, it's not all that complicated because it really is just quite a bit of pushing. There's a lot of -- in a budget of that size, obviously, there's a lot of things moving around from time to time. But they tend to find themselves towards the mean, and that's precisely the way this came out this year as well.

[Operator Instructions]. We will take our next question from Christine Cho with Barclays.

Just wanted to make sure I understand this agreement with Targa. Are the economics here really going to be driven by the volume growth out of the Rocky Mountain Midstream JV? And also, any color around when you expect to achieve that EBITDA multiple of 6x and what sort of volume we should assume is underpinning those economics?

It's Micheal. Just -- to start on the first part of that, we see a lot of growth not only from the Rocky Mountain Midstream, but we've got barrels on our Rockies plants that are already out there that will be moving on the Bluestem pipeline eventually. As you know, we've got the partnership on the OPPL system. And we'll continue to move with Rockies barrels down the OPPL system to Conway and then further south on Bluestem. And with our 2021 in-service date on Bluestem coinciding with Targa’s build to the north with us, we would expect a lot of those barrels to move south and ultimately, get to a 6x multiple on that. And really, a lot of that is driven by timing of the barrels coming out of Rocky Mountain Midstream frankly, but we do see some pretty significant growth in the Rocky Mountain Midstream assets, especially with the agreement that we just executed, and so we would anticipate approaching that 6x multiple pretty quickly.

And just to clarify, the volumes coming out of like your existing plants, are those priced off -- those are priced off Conway, right? And so to the extent that you can bring them down to Bellevue, that's going to be margin that you keep for yourself. Is that how I should think about it?

There's a variety -- for our own equity barrels today, we have the option of either Conway or Bellevue at a differential in price. So today, we do have that option for those barrels up to an amount that we can move under the existing exchange agreement. So I would just say that we do have Bellevue access for those barrels today to the degree it's available. But for the Rocky Mountain Midstream barrels, that's a different story in terms of being able to include those because we're limited on capacity on Overland Pass right now. So as Overland Pass opens up, that allows us to make a very nice margin by making these investments on the downstream.

Got it. Okay. And then just switching over to the Northeast, the gathering volumes have been great, but the processing volumes have been flattish for the last year. What do you think we need to see to have these volumes increase?

Well, Christine, I would say we do expect those volumes to increase. We have line of sight to what the producers are doing. There's a lot of drilling activity behind our processing plants that will be coming online this year. It's a little bit delayed for more than where you had thought it would have been last year. That's really coinciding very nicely with the completion of growth TXP-2. And so we have very good confidence that our current capacity will be filled probably in the second quarter, and that's about the time that TXP-2 and Oak Grove comes online. So we anticipate certainly [filling] [ph] TXP-1 this year and TXP-2 will start processing gas shortly after that.

Christine, I would just add to that question, and it's a good observation on your part. I would just add, we've got several significant upstream projects, like [Checkmark] [ph] pipeline and some other projects that are -- that we have to get completed before we can bring those new processing of those volumes in for processing. So there's quite a bit of infrastructure having to happen upstream to be able to get some of the new drilled volumes from Southwestern and other customers into the front of Oak Grove and we're nearing completion on a lot of that work.

And Christine, I probably should add to that, we have been in volume commitments whenever we agree to go deploy capital there at those processing facilities. We have MBC to back that up. And so that's why it gives us a lot of confidence that those volumes are going to show.

Our next question comes from Jeremy Tonet with JP Morgan.

Maybe just kind of speaking up on that last point there. There's been kind of concern with regards to producer activity in the Northeast and some producers kind of taking in that growth rate, focusing more on free cash flow. I was wondering if you guys could address how you see that impacting your footprint because it seems like some of the guys behind your systems might be taking a bit of a different task than others there. If you can extend on that, what gives you guys the confidence in the Northeast growth as you expected?

Sure. I'll just take that at a high level and then and Micheal can fill in with some details if required. First of all, I think not all producers out there are created equal, and certainly not all acreage is created equal. And so for instance, if you look at Cabot, which is one of the primary drivers of our growth, they continue to show a very strong growth profile because they've got markets established upwards towards 4 Bcf a day of markets that they've established. And so they've done a great job of getting the markets out in front of them, and we're working furiously to keep our gathering system expanded to keep up with them. So that's very obvious to us where that growth is coming from in that area. As well as Bradford County area continues to grow very rapidly for us as well. And so as Micheal pointed out earlier, we have a lot of transparency into that growth in that area. And then as you move into the South, I would just say that while there has been some folks pulling back a little bit on volume growth, as Micheal mentioned, those MBCs that people have made to us, they're going to work hard obviously to build those up. They are being very successful with the production behind there. And I would just tell you the 15% CAGR that we put out there earlier, we had quite a bit of room, if you will, between what producers were forecasting at that point versus that 15%. And so we're still very -- feel very confident in that 15% CAGR that we put out earlier based on the detailed work that we do with producers. I would say, as I've mentioned earlier, probably the one more positive things about that growth that's occurred is the Encino acquisition from Chesapeake on that Utica acreage, which was a very large piece of volume and acreage behind us that was declining previously. And now with their activities, we're actually starting to see that growth. So that's a really big positive for us in terms of offsetting some of the declines that exist there, yes.

That's very helpful. Just wanted to turn to Atlantic-Gulf here real quick. And you had quite a nice quarter there. I was wondering this kind of -- something that's a run rate level for you guys? Or is there still more kind of Sunrise is not fully baked in for the quarter and you're continuing to see growth there? How should we think about that segment?

This is Micheal again. I would say the majority of the quarter, we saw the Atlantic Sunrise revenues in there came online October 6 is when we started charging full rate for Atlantic Sunrise. But recall, earlier in 2018, we were also charging for some interim capacity that we were able to achieve there. We were able to bring the full volume on October 6. So basically, you would see the fourth quarter having the majority of the revenue in there for Atlantic Sunrise. And if you recall, it's a revenue payment -- sorry, a capacity payment. On a revenue throughput, although very strong throughout the fourth quarter, doesn't drive a lot of the revenue differences there because of the capacity reservation charges that Transco enjoys.

And from RBC Capital Markets, we'll hear from TJ Schultz.

Just one thing on the last point on the Chesapeake, Utica acreage now with Encino. Can you find any better rated change you're expecting from an asset those in decline. Now it sounds like more activity. Just any notable color from early days of Encino in place.

Well, they're still on their process deciding how aggressively they want to go after it, but I think it's a -- the big shift, of course, is a -- the available capital that Encino has through the Canadian pension fund. And so they are anxious to put that capital to work and driving returns on that. So it takes a while to get ramp back up from the declines that had been occurring in the area, but we're working with them to make sure that we keep the infrastructure out in front of them right now. So I think it's a question of how many rigs that they're going to run in the area right now. I think they're planning -- they've got two and planning on maybe going to three at this point. And so that will -- that's what will drive that. And of course, they're very efficient. They've got a lot of team that was already existing there, very efficient operators. And with three rigs, they'll be growing pretty rapidly in that area.

Okay. Great. Just one more, on Gulf East, if you could just clarify a little on Appomattox. It sounds like coming on a little sooner than expected. If you can just remind me the status of the Northwest Pipeline auction to you. And just, in general, what you're expecting from the ramp in that area this year?

Sure. TJ, yes, we have completed all of our work and the pipeline auction and it gets triggered just ahead of production coming online. So we're in those discussions and that's all pretty -- I would say that's very clean and very baked, and there's not a whole lot to happen there other than us making decision to exercise that. So really, it's just a matter of Shell doing their work on Appomattox and being ready to flow. And so that's what will drive the timing on that is their work on the Appomattox platform and getting that ready to flow. And they've done a great job, really great execution on Shell team on being so far ahead of schedule as what they had planned originally. And our team did a nice job as well having our side of the infrastructure done. So we're excited about it, a lot of volumes just from the fuels proper, but a lot of new work going on by both Shell and other producers in the area and acreage around that, that would be nice [indiscernible] to the Northwest to our infrastructure out there. So I think that's going to wind up being even bigger than we had originally planned in terms of the number of fields and new development that's going on out there. Both -- again, both by Shell and Chevron's activity in the area as well.

Our next question is from Dennis Coleman with Bank of America.

If I can just go back to the Bluestem project to start. I wonder if you might talk a little bit, how did you first scope the project in terms of deciding where the connect would come and who would build the what with Targa?

Well, we did say that Targa had -- and this is why it turned out to be such an attractive project for both parties, was because they were building up to that Kingfisher area anyway to capture other volumes in the Midcontinent area there. So this was a low-cost expansion for them to be able to pick our volumes up as well for them. So the transaction and the rates that we enjoy, we're benefiting from that. And so it was just a matter of us placing the capital to build down from Conway down to where they were already going to be picking up other barrels in that area.

Okay. And so are there -- there's contracts on these systems already? Is that -- there's a contract structure in place, there's shippers, or is it Williams that's the shipper?

Yes. On our system, it would be own -- of course, remember, you have Overland Pass that we own 50% with One Oak upstream of this. That comes into the Conway area and then we would own that system 100%. We would be the -- in terms of shipping on that, we would have an exchange agreement, purchase agreement with Targa for some of those barrels and we will have relationships with upstream producers. Plants that's in the Rocky Mountain area will have relationships where we will be buying their barrels at a fixed margin in that area. So we'll have a combination of both our own equity barrels, which are very substantial today as well as barrels that we've been continuing to pick up in the DJ Basin and some of the surrounding area there.

Okay, got it. And then just there's a word in the press release that I want to just try and understand. You said there's an initial 20% option on one the fracs. I guess, that implies that there will be additional options or potentially, is that -- am I hearing that right?

Yes. Great question. As I mentioned earlier, we structured the transaction so that we can expand both our equity investment and the frac, but that would come with additional volume commitment on our part as well, and so that's kind of how it's structured, so -- but we built in flexibility, knowing how robust we're kind of forecasting the growth in the Rocky Mountain midstream area to be, we want to be prepared to be able to handle those incremental barrels. And so while today, we don't want to make that kind of commitment without seeing the barrels actually show up, we did want to make sure that we had the capacity to allow for that growth coming from that area.

Okay, great. And then I guess, maybe just one on the leverage. It seems that, that further reduction is primarily a function of asset sales. So I wonder if you might talk about what kind of -- any assets that you're particularly looking at. Is there a program going on now or is that going to be more opportunistic?

No, I would say we're constantly looking at optimizing our portfolio and. Where we are working really hard, I can tell you the entire team, with the board's support, is working hard to reduce our leverage. And so we continue to work various transactions and asset sales that would help complement that. So to answer your question, we are actively pursuing those type of transactions.

But I would -- this is John Chandler. I do want to say, even without that, though, again, remember, we're generating around $1.2 billion of excess cash even with attractive dividend growth, and we can use that cash even on new investment dollars. So we actually are deleveraging even with investments in new projects because we're funding so much of it with cash. So again, after sales will enhance and speed up the deleveraging, but we're deleveraging even without asset sales.

Next we'll hear from Mike Lapides of Goldman Sachs.

Two questions unrelated to each other. One, is there an update on the siting and permitting process for the Northeast Supply Enhancement that you can provide? Just in general, it seems like federal processes are kind of running as expected but just curious given a lot of the challenges others and you all have paid in terms of building pipelines into New York and dealing with kind of state level intervenors or stakeholders.

Michael, this Micheal. I will give you an update on that. This is a great project for us to be able to facilitate the reduction of emissions in New York City as well as improve the cost profile of people's energy use there. We just recently received our final environmental impact statement from the FERC and we would expect within 90 days, further regulations and their practice to provide a FERC certificate, assuming the FERC commissioners approve that within 90 days. So you would expect to see that hopefully within the 90 days and then we're in the process on the state side of getting the 401 certifications from New Jersey and New York. Both of those state agencies had scheduled public hearings for the 401 certifications with just recently, the state of New York giving the notice of complete application on our 401 certification. And so we'll go through those processes with the state of New York as well. And once those 401 certificates are issued by each one of the states, then that allows the core of engineers to issue let's call the 404 permit, and FERC that into consideration in order to give us a notice to proceed with construction. So we've got all that to occur within the next several months.

Got it. Much appreciated. And also, totally different topic. Any update you can provide on the Transco rate case, just in terms of whether settlement talks are underway and whether there's a potential for settlement or whether you think goes the full litigated route?

I can give you an update on that as well. So we would expect to see the -- what's called the top sheets from FERC in mid-March, and that's really their staff's reaction to our filing. And they would provide the sideboards, if you will, so what we could then go to settlement negotiations with for staff and our customers on. And so the first or the start, I should say, the next settlement conference is scheduled for the end of March. And so at that point in time, we'll have a pretty good idea of how likely it is that a settlement can occur. And obviously, that's the path we would prefer to go down. I think that's the best for our customers and ourselves to be able to agree upon that and not litigate the case. And that's what the expectation is right now, for us to achieve an outcome in settlement that's satisfactory to both Williams and our customers.

With Tuohy Brothers, we'll hear from Craig Shere.

A couple detail items and then a bigger picture question. Maybe my math is off but it looked like there was an unusually high tax rate reflected in adjusted income. If that's correct, what was driving that?

It's really a couple of things. This is John Chandler. There's a couple of things that drive that. Number one, in the fourth quarter is when we usually do our tax provision re-estimation for the year, so I'd encourage you to look at the entire year at the tax rate instead of just the quarters since we do have some noise around that. I'd also say we had several obviously large unusual items in the fourth quarter, including the impairment and other things, that when we do estimations of taxes and the impact of taxes on those unusual items, we use a 25% rate, which is actually higher than our average blended rate for the quarter. So that results in some skewed tight calculations because we're using a different rate for our adjustment items, our normalization items. We use our standard annual rate of 25% than what it actually blended to. It's probably confusing but I'd just ask you to reach out to our IR team. I think they can walk you through that. But so it's really those two things, the significant usual items and the tax position adjustments that are done in the fourth quarter.

Looks like the EBITDA was in line but the adjusted EPS is a little off and that explains a lot. Alan, in your prepared remarks, you talked about several other Transco projects not going public with you yet. Can you give us a picture of the range of opportunities in terms of size? And maybe any updates on the Transco project one that was heavily foreshadowed on the 3Q call?

Yes, sure. First of all, on project 1, remember we had two there, we had project 2, which was Leidy South, which is moving ahead very nicely and fully contracted. Project 1, we continue to work with the counterparty, a primary counterparty on that. And I would just to continue to be very interested in the project and highly supportive of the project but have some of their own internal issues to get through to be able to transact with us. And -- but we remain very confident in the fundamentals on the drivers behind that project. I would also say though, we have several other new projects that are well on their way to development. A lot of strong interest that would continue to alleviate capacity constraint out of the Northeast PA area. And so we're pretty excited about that and that also helps expand in some of the markets that are continuing to need expansion. And despite what you might hear, those markets are growing pretty nicely in terms of their demand for natural gas there in Zone 6. And so we've got several projects that are pointing at that and again, the interest in those projects is very strong, I think.

So it sounds like there's incremental pipeline development that can further add to the Northeast GMP opportunities.

Absolutely, yes. And I'm not going to call it project 3 because we're growing weary of that. But it is a nice project flowing right behind the other two.

Okay. And here is a little bit of my bigger picture question. I understand the Barnett is not a 2019 headwind, but I want to get some sense of the longer-term gives and takes at GMP. If we look out to 2021, as you targeted a 15% CAGR on Northeast GMP volume growth off 2018, depending on assumed margin growth for them, is it reasonable to assume that Northeast GMP EBITDA can rise $600 million to $900 million plus off '18 levels? And then would Barnett maybe be a headwind of as much as $150 million?

Yes. We're not going to provide guidance individually on Barnett. But I would say this, Craig, the lowering or the impairment we took on Barnett is -- I don't want to drag everybody through all the accounting details, but we were -- that asset was held according to the undiscounted cash flows on the assets when the -- and obviously, that was dependent on gas prices in the area, both -- by the way, that contract is set up as well as drilling expectations from Total, our primary customer in that area. When the Permian price for -- so every year, we test an asset like that for its cash flows, looking forward against the held value. And this year, when we had to take into account the very large basis differential in the Permian and how that would affect both the rate that we received as well as the actions of what we've estimated would be the actions of the producing customer, that brought us down below that estimate. And therefore, that triggered us to have to remarket the fair value. In other words, what we think we could sell the asset for in the market. And that was very different than the sum of the undiscounted cash flows, which -- what was related with Mark earlier. So it was a -- said another way, it was a relatively small movement in expected cash flows from the asset but it put us down below that fair value and that triggered a different way of value in the asset, and that's why we got such a large impairment. So you shouldn't read into that, that the business is collapsing there but it moved enough on the far out values, it moved enough that we had to reposition the way we value it. So nothing's really changed all that much there other than, again, the Permian gas supply hits -- if the Permian pipelines all got filled adequately and we see the Permian gas prices come back up, then that avenue would change for that area. But for the meantime, we have to take the facts as they are and look at the forward curve for the basis differential out there.

And I'd just add to that. If you go to the third quarter of 2017, we impaired our Midcontinent asset that was the same scenario that was set up. There wasn't a material change in the actual EBITDA generation from any kind of assets, but the gross cash flow dropped in the -- to make us take it from historically high carrying value down to its fair value. So, same is happening with the Barnett. We don't see any meaningful change in the EBITDA streams but it was just enough to trip that write-down from carrying value to fair value.

No major change even looking out say, to 2021?

No. Not really. Just the impact of gas prices long term for the asset just brought it down just enough. So we do not see a major shift in the cash flows from that business. We have had pretty modest growth expectations in the past for that, but this effectively just stripped that out, and the growth expectations completely stripped out of there in terms of drilling activity. And so that's what -- but we have had very modest expectations.

And finally, the bookend that I put out there depending on margin per M of Northeast GMP gaining say, $600 million to $900 million plus in EBITDA over 2018 through 2021. Is that a decent bookend?

Well, I would just say we are very much on our way towards that $0.50 to $0.55 EBITDA per Mcf range that we've talked about earlier. And so with the volume growth and with that kind of margin improvement, the answer is yes. But I'm not crystal clear on the timing that you're laying out, just to be very, very thought through that versus that amount. But in terms of what we laid out here at Analyst Day, we're feeling very good right now about both the volume growth and the margin growth that we're experiencing.

From Wells Fargo, we'll hear from Sharon Lui.

If you look at, I guess, the annualized Q4 numbers for your adjusted EBITDA from equity investments, it sounds like you kind of suggest a much higher run rate versus your 2019 guidance of $825 million. And I guess if you assume contributions from Jackalope as well as Rocky Mountain continue to ramp, maybe help us try to reconcile to your 2019 outlook based on what you guys reported in Q4.

John?

Off hand, I don't know if I have the details in front of me to be able to answer that, so I might have you call Dr. John Porter on that question.

Okay, sure. And I guess, just a housekeeping question on the impairment charge. So there's no impact on cash flows, only on DD&A expense. Is that correct going forward?

If there is an impact on cash flow, that's very minimal on Barnett. So yes, it's just that it's an uplift or it's an improvement or reduction of DD&A, that's correct.

Okay. And then the amount that Williams actually recognized in terms of the amortization of deferred revenues, is that still about $100 million going forward?

Yes, that sounds right. Yes.

Next up is Jean Salisbury with Bernstein.

Just a couple of quick ones for me. So it seems like Mountain Valley and the Atlantic Coast project has hit some difficulties. And as you articled that one of these projects is ultimately canceled, could Transco address that demand with new laterals? Like, could that be a source of new projects?

We are very well positioned on the market end for those projects. In other words, being able to help usually existing right away, but not solely. So said another way, some of that market expansion will be required, but I would certainly say that we have a lot to offer in that regard in terms of the use of our existing right aways and systems to be able to help supply that growth. So yes, we have a lot to offer there to the degree that, that occurs. But I would also say that particularly as it relates to Mountain Valley, that there's so much continued growth in demand on our system that those supplies coming in, we're going to be -- we'll have synergies with Mountain Valley whether it gets filled as planned or not, we would have quite a bit of synergies there with that system. So I would say there's little different because they serve two very different needs, but clearly we have the ability to help out both projects.

That makes sense. And then just a quick clarification. That Bluestem EBITDA is all incremental from the EBITDA that you'd expected on the initial Discovery deal. I assumed, so I just want to make sure.

Yes, I think that's probably a good way to look at it. We did anticipate some NGL uplift in the Rocky Mountain midstream acquisition model. So we knew that we would be able to acquire some of those barrels ultimately, and so that's factored into that.

Okay. So maybe a little bit of double dipping but a lot of it's incremental?

Yes.

I would say this though. When you collective put in the investment on Bluestem with the investment in the Rocky Mountain midstream assets, we still accomplished 6x multiple even on even a combined investment when hopefully that system is fully up and operational.

Next up is Colton Bean with Tudor Pickering Holt & Co.

So Alan, you mentioned that continued focus on portfolio management, so just wanted to touch on that. With the vertical integration here of the Rocky Mountain processing fleet with some further downstream opportunities, does that change the way you assess those assets and kind of how they fit in the broader asset footprint?

No. I would say that the -- we will always look to vertical integration as one of the facets to consider when we think about whether an asset is strategic or not. Because obviously, the aggregation of barrels, for instance, gives us value opportunities, investment opportunities just like Bluestem. So we definitely think about, when we think about what assets we would want to hold and that we add value as an organization, as a corporation, what we add value to, that vertical integration is obviously a key part of that. So that is a facet that would be dependent on and certainly to the degree that we've got combined downstream investments. It makes those assets more valuable to us as a company often than to somebody else. And so I think that's the best way to think about that.

Got it. That's helpful. And then just to touch brief on the West. So you mentioned gathering volumes net of the Four Corners adjustment there, down around 3% Q-on-Q. Just interested in what you're seeing on the Haynesville system and maybe a longer-term outlook there as well.

Yes. As we said in '17, we had a really big growth rate on Haynesville in '17, and we forecasted that we didn't expect that to occur again in '18 because that -- there was so much new plus production and the decline rates on that new plus production is pretty high. So and we -- at the first of the year, we actually saw some growth but towards the end of the year, we did see some decline on the Haynesville system, so -- and most of that from Chesapeake production. The good news is on the Haynesville system is our team has been doing a really nice job of capturing new acreage out there from third parties other than Chesapeake. So we're encouraged for the way that looks, not on the base dedicated acreage out there, not really a change on that, but in bringing -- we've been winning some new business out there. So that will help to maintain the volumes in the Haynesville.

Great. And just on those incremental agreements. At a high level, could you comment on whether those are weighted towards public or private producers?

Mostly private.

From Jefferies, we'll hear from Chris Sighinolfi.

I'm not sure if this one's for you, Micheal or Chad, but I do want to circle back on the NGL project just one more time, more from a philosophical perspective, I guess, regarding the Conway market. You guys had made clear, the advantage of gaining better access or greater access to Bellevue through Targa's system, both the pipe and the frac. And it's clearly an advantage moving barrels on your own system versus a third-party system. So I guess, two follow up questions with regard to that set up. First, your views on the Conway purity product market outlook over time and your regional frac volumes there, given these announcements seem all Y-grade in nature. And then two, do you have Y-grade contracts now on third-party assets south from Conway that you can transition to Bluestem Grand Prix over time? And if so, what sort of schedule should we anticipate there?

A lot of questions, I'll take a stab at a few. Let's see. First of all, on the Conway market, yes, and I think it's important to know that if we flatten out the spread between Conway and Bellevue, we're a winner in that. So you should think about that being somewhat of a natural hedge for our business because we already own those assets. And so to the degree that Conway product -- spec product prices go up in the purity markets, then that makes Conway and the services that we offer there that much more attractive, so that's a way that we think about that, obviously. And in terms of whether that's spec product or Y-grade, that's just a matter of how much incremental fractionation capacity there is on both ends of the pipe, basically in terms of being able to make those markets. Let's see. And yes, we do have contracts with third parties on Y-grade that have fixed margin built into them.

Okay. And is that something we can expect in a reasonable timeframe, maybe the next 2 to 5 years, to be up that could transition to this new collection of Williams-Targa assets? Or is it a long...

Yes, absolutely. No, those are -- I would say, when we start up in 2021, I think we'll be well positioned there to be able to start taking advantage of that immediately.

Okay, great. I guess switching gears and just a quick follow-up for me on one of Jean Ann's earlier questions. You had noted that when you entered the DJ JV with KKR, that you pertaining some options to acquire from KKR additional interest. And so I'm wondering, Micheal, you had said that you contemplated other NGL solutions as part of that investment. I'm wondering now that they're getting more formalized with this agreement with Targa, if it shapes your view on whether or not or how swiftly you'll exercise options with them.

Yes. I would just say first of all, we've got 7 years, I think, total on that option, so a long time to the decide what that is. And I'll just remind you, the investment that we have with KKR is solely the GMP assets. And so, there's not an investment in the downstream value chain on that outside of that JV, it's just in the GMP assets that are proper. So it doesn't really affect so much that option value, if you will, because it's really just going to be the cash flows from that GMP business that will drive the option value there. But it does -- I would say, the relationship there with KKR is very solid, well aligned. And the fact that we have that option does keep us very focused on driving the value in the JV as well. So it's actually a pretty nice feature in terms of keeping us aligned there.

And us being able to provide these NGL solutions downstream creates value for the partnership there with KKR because we can go to the producers and provide a value chain there that we can give them fixed pricing.

And Alan did mention earlier that what we've been successful is some new connections there at pretty attractive returns. You remember, our option with KKR is at a fixed return, so to the extent we can add new gathering business at higher returns, it just becomes that much more valuable, of course, in the future to exercise that option.

And so I guess, final point on that then, John. Assuming your -- the guided leverage number you gave for '19, is it safe to assume that, that does not include any option exercise on that asset?

That's does not. That's the beauty of this agreement. We have quite a period of time to execute that, so we've got plenty of time to continue to bring our leverage down and find that opportunity sometime in the future to execute that option.

There are no further questions at this time. And I'd like to turn the conference back to our speakers for any additional or closing remarks.

Okay, great. Well, thanks everybody for joining us. Really excited about the platform for growth that we've got set here for '19. Teams continue to work very well together to take advantage of all these opportunities. And I would say our execution just continues to get better and better and really proud the way the teams are operating. And we like the macro conditions that are set up ahead of us, as well. So feeling very good about both 2018 and the platform for growth that we've got set up for '19 and beyond. So thank you again for joining us.

This concludes today's conference. Thank you for your participation. You may now disconnect.