Williams Cos Inc (WMB) — Q4 2018 Earnings Call Transcript

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.

Good morning, everyone. Thank you, John. I’ll begin by discussing the macro conditions that are supporting our strategy. Natural gas demand continues to drive our approach, and we observed an 11% increase in overall natural gas demand in 2018, building on significant demand growth from 2017. Forecasts suggest another 5% increase expected for North America, indicating continued demand growth. This aligns with our expectation that not only the U.S. but also the global market is leveraging the U.S.'s capacity to produce gas affordably. To put the 11% increase in perspective, it surpasses total dry gas production from the Permian in 2018, highlighting the importance of demand growth in our strategy. I'm pleased to report that our natural gas infrastructure portfolio performed even better than expected last year, achieving record levels for adjusted EBITDA despite over $4.6 billion in asset sales over the last two and a half years, which have reduced our commodity exposure and improved our leverage metrics. We initiated 2018 by setting delivery records on Transco, and we repeated this during a recent cold snap. The Northwest Pipeline also recorded its highest throughput ever, exceeding the previous year’s volume. The increased demand is clearly reflected in our pipeline performance. We executed the critical WPZ rollup transaction, which has repositioned Williams as a simplified C-Corp with investment-grade credit. Amidst a challenging regulatory environment, we achieved milestones for critical Transco projects including Garden State and Atlantic Sunrise, and we are making strides with additional major projects. We also saw the start of accelerated growth in our Northeast gathering and processing segment, and expanded our ESG disclosures and board with new appointments. Our capital discipline remains strong as we entered the DJ Basin, funded by exiting our previous Four Corners position. Looking ahead, our low-cost natural gas strategy positions us well for predictable growth in 2019, and we are reaffirming our guidance for the year. Now, let's take a closer look at our financial performance compared to our guidance for 2018. Although our GAAP net income was impacted by an impairment on our Barnett gathering system, our adjusted net income and EPS both exceeded guidance. Our adjusted EBITDA and dividend coverage ratio also reflected strong performance. Our growth capital expenditures were about $300 million under guidance due to timing shifts, which will impact our 2019 guidance. We ended the year with leverage at 4.8, reflecting strong financial performance compared to our guidance. In reviewing the fourth quarter results, GAAP numbers showed some year-over-year variations due to significant accounting entries, but adjusted EBITDA rose slightly compared to 2017. Normalizing for revenue recognition changes and the sale of our Four Corners system, adjusted EBITDA actually increased significantly, especially in the Northeast and Atlantic-Gulf segments. For 2018, the adjusted EPS grew to $0.79, reflecting a 25% increase from the previous year. Adjusted EBITDA grew over $300 million compared to the prior year, driven by volume increases in the Northeast and Atlantic Gulf segments. Additionally, we completed several key projects, showcasing effective project execution and permitting progress. On the operational side, our Northeast segment saw impressive gathering volume growth. Transco set new peak delivery records, emphasizing the critical role of our pipelines. Moving on to our newly announced project, Bluestem, this will enhance connectivity between Western NGL supplies and Gulf Coast markets, and we anticipate substantial opportunities for growth with our partner, Targa. We expect an investment of $350 to $400 million for this project, primarily in 2020. Regarding 2019 financial guidance, we are maintaining our performance expectations, while revising growth capital expenditure guidance to reflect the shifts in spending from 2018 to 2019. We will continue our focus on improving credit metrics and executing our capital discipline strategy. Finally, we've decided to shift our annual Analyst Day to later in the year for better alignment following our board strategy session. Now, let's move to the Q&A session.

I want to begin with the new project that you announced last night. Moving forward, do you anticipate accumulating more barrels? Is there a possibility of requiring more than a 20% stake in a frac? Additionally, do you have an estimate of the stack rate needed to get the Y-Grade all the way to Mont Belvieu?

I would say, first of all, regarding the volume growth, we have incorporated flexibility in our relationship with Targa to expand our volumes as necessary, including transport capacity and investment in the fractionator. We see significant opportunities to continue increasing new barrels from both the DJ and the Rockies, and we are excited about that. We also appreciate that Conway becomes a vital hub as we open it to new markets, which adds to our enthusiasm. As for the rate, we won't disclose it, but I can say it is very competitive and we're pleased with how it's structured. Targa views this as a long-term strategic partnership, and we feel the same way. Thus, we see this as an excellent opportunity to optimize 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 like to mention that we remain focused on the Permian, as highlighted by our recent announcement regarding the Brazos Midstream system. We plan to maintain a disciplined approach, and although two projects have been announced for transporting gas to the Gulf Coast, we are exploring additional options. The Brazos system allows us to develop projects that connect to the Gulf Coast, similar to our move into the DJ. If we decide to pursue such projects, we are likely to partner with others to enhance efficiency. We will continue to operate in this way.

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, most of the capital for Bluestem will be spent in 2020. So that's primarily why you're not seeing much movement in that area. It's not complicated because it really involves quite a bit of adjustment. In a budget of that size, there are many factors that change from time to time. However, they tend to balance out, and that's exactly how this year turned out as well.

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. To start on the first part of that, we see significant growth not only from the Rocky Mountain Midstream, but we also have barrels from our Rockies plants that are already positioned to move on the Bluestem pipeline eventually. As you know, we have a partnership on the OPPL system. We will continue to transport Rockies barrels down the OPPL system to Conway and then further south on Bluestem. With our 2021 in-service date on Bluestem aligning with Targa’s northern build, we expect many of those barrels to head south and ultimately achieve a 6x multiple. Much of this is driven by the timing of the barrels coming from Rocky Mountain Midstream, but we anticipate considerable growth in the Rocky Mountain Midstream assets, especially with the agreement we just executed. We would expect to approach that 6x multiple fairly quickly.

To clarify, are the volumes from your existing plants priced off Conway? If you can transport them to Bellevue, that will be margin you retain for yourself. Should I think about it in that way?

We currently have the option to choose between Conway or Bellevue for our equity barrels at a price differential. We can utilize this option for a certain amount of barrels under our existing exchange agreement. Currently, we have access to Bellevue for these barrels as long as it's available. However, the situation is different for the Rocky Mountain Midstream barrels due to our limited capacity on Overland Pass. As Overland Pass becomes more accessible, it will enable us to generate a substantial margin by making investments 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 TXP-1 this year and TXP-2 will start processing gas shortly after that.

I want to expand on that question because you made a great point. We have several important upstream projects, such as the Checkmark pipeline and others, that need to be finished before we can start processing the new volumes. A lot of infrastructure work has to be completed upstream in order to bring in the newly drilled volumes from Southwestern and other customers to Oak Grove, and we are close to finishing much 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.

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 provide a high-level overview and then Micheal can add more details if necessary. Not all producers and land are the same, and a good example is Cabot, which is a key driver of our growth. They have established markets that reach up to 4 Bcf a day, positioning themselves strongly for growth. We are working hard to expand our gathering system to keep pace with them, making the sources of that growth clear to us. Additionally, the Bradford County area is also experiencing rapid growth. As Micheal mentioned earlier, we have a lot of insight into the growth in that region. Moving to the South, while some producers have slightly reduced their focus on volume growth, they are committed to building their metrics and are seeing success in production. Our 15% compound annual growth rate remains achievable as there is a substantial gap between what producers are forecasting and that figure. We maintain confidence in this growth rate based on thorough collaboration with producers. A significant factor contributing positively to our growth is the Encino acquisition from Chesapeake of Utica acreage, which previously saw a decline but is now showing signs of growth due to their efforts. This development helps to offset existing declines in that area.

That's very helpful. I wanted to ask about Atlantic-Gulf quickly. You had a strong quarter there. Is this level of performance sustainable for you? Or is there still potential for further growth from Sunrise that hasn't fully materialized in this quarter? How should we evaluate that segment?

This is Michael again. During the majority of the quarter, we saw revenues from Atlantic Sunrise start to come in after we began charging the full rate on October 6. Earlier in 2018, we were also charging for some interim capacity that we had managed to achieve. We were able to bring the full volume online on October 6. Therefore, you can expect that the fourth quarter will reflect most of the revenue for Atlantic Sunrise. It's important to note that while revenue throughput was strong throughout the fourth quarter, it does not significantly influence revenue differences due to the capacity reservation charges that Transco benefits from.

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.

They are still in the process of deciding how aggressively to pursue it, but a major change is the capital that Encino has access to from the Canadian pension fund. They are eager to invest that capital and generate returns. It takes time to recover from the declines in the area, but we are collaborating with them to ensure the infrastructure is ready. The key question now is how many rigs they will operate in the area. Currently, they have two rigs and are considering increasing to three. This will be a significant factor in their operations. They have a capable team already in place, and with three rigs, they will be growing quickly in that region.

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. We have completed all of our work on the pipeline auction, which will be activated just before production starts. We are in discussions about this, and everything is pretty straightforward and settled from our side. The only thing left is for us to decide to move forward. The timing will be driven by Shell's work on the Appomattox platform and their readiness to begin production. Shell has done an excellent job, performing ahead of schedule compared to their original plans. Our team has also finished our part of the infrastructure, so we are looking forward to it, expecting significant volumes from the fuels as well as additional work from both Shell and other producers in the area. There are promising developments around the Northwest that will complement our infrastructure. I believe the overall project will be larger than we initially planned due to ongoing developments by both Shell and Chevron in the region.

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?

We mentioned that Targa found this project appealing because they were already expanding into the Kingfisher area to capture additional volumes in the Midcontinent region. This made it a cost-effective expansion for them to also include our volumes. As a result, we are benefiting from the transaction and the rates we have. It was about us investing the capital to connect from Conway to the area where they would already be gathering other barrels.

Okay. Are there contracts on these systems already? Is there a contract structure in place, and are there shippers, or is it Williams that is the shipper?

Yes. We own 50% of the Overland Pass with One Oak upstream, which feeds into the Conway area that we would fully own. Regarding transportation, we have an exchange and purchase agreement with Targa for some of those barrels, and we will establish relationships with upstream producers. We will also engage with plants in the Rocky Mountain area to buy their barrels at a fixed margin. Our supply will include both our significant equity barrels as well as those we continue to acquire in the DJ Basin and nearby areas.

Okay, I understand. I noticed a term in the press release that I need clarification on. You mentioned there’s an initial 20% option on one of the fracs. Does this suggest that there will be additional options or am I interpreting this correctly?

Yes, that's a great question. As I mentioned earlier, we structured the transaction to allow for an expansion of both our equity investment and the frac, which would involve additional volume commitments from us. This structure provides flexibility, considering our strong growth forecast for the Rocky Mountain midstream area. We aim to be prepared to manage any incremental barrels that may come in. While we are not ready to make such a commitment until we see those barrels arrive, we wanted to ensure we have the capacity to support that anticipated growth.

But I want to say, even without that, we're generating around $1.2 billion of excess cash, even with attractive dividend growth, and we can use that cash for new investment dollars. We are actually deleveraging even with investments in new projects because we're funding much of it with cash. So after sales will enhance and speed up the deleveraging, but we're deleveraging even without asset sales.

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 provide an update on the Transco rate case. We anticipate receiving the top sheets from FERC in mid-March, which will reflect their staff's response to our filing. This will outline the parameters for settlement negotiations with staff and our customers. The next settlement conference is set for the end of March, at which point we should have a clearer idea of whether a settlement is likely. We prefer to reach an agreement that benefits both Williams and our customers, rather than proceeding to litigation. Our current expectation is to achieve a satisfactory settlement outcome.

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, certainly. Regarding project 1, we had two projects, with project 2, Leidy South, progressing well and fully contracted. We are continuing to collaborate with the primary counterpart on project 1. We remain very supportive and interested in the project, although they are facing some internal challenges that need to be resolved before we can proceed. Nevertheless, we have confidence in the fundamental drivers of the project. Additionally, we have several new projects in development, which are attracting strong interest and will help alleviate capacity constraints in the Northeast PA area. We are excited about these developments, which also contribute to the expansion in markets that continue to require growth. Despite external perceptions, those markets are demonstrating significant demand for natural gas in Zone 6. We have multiple projects focused on that area, and the interest in them is quite strong.

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?

We're not going to provide specific guidance on Barnett. However, the impairment we took on Barnett results from the asset being valued based on undiscounted cash flows, which rely on local gas prices and drilling expectations from Total, our main customer in the area. Each year, we assess the asset’s cash flows against its held value. This year, the significant basis differential in the Permian affected both the rate we received and our expectations for the producing customer’s actions, which lowered our estimates. Consequently, we had to reevaluate the fair market value of the asset. This new assessment led us to recognize a substantial impairment. This shouldn't be interpreted as a collapse of the business in that area; rather, it reflects adjustments based on long-term forecasts. If Permian pipeline capacity improves and gas prices rise, we could see changes in that region. For now, we need to consider the current facts and the expectations for future basis differentials.

I would like to add that in the third quarter of 2017, we impaired our Midcontinent asset under similar circumstances. There was no significant change in the actual EBITDA generation from any of the assets, but the gross cash flow decreased enough to require us to adjust its value from historically high levels to fair value. The same situation is occurring with the Barnett. We are not seeing any substantial changes in the EBITDA streams, but it was sufficient to trigger a write-down from carrying value to fair value.

No major change even looking out say, to 2021?

No, not really. The long-term impact of gas prices on the asset brought it down slightly. We do not anticipate a significant change in cash flows from that business. Our previous growth expectations were quite modest, and this situation has effectively eliminated those growth expectations, particularly regarding drilling activity. We have maintained very conservative 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.

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.

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 articulate 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 in a strong position in the market for those projects. This means that we can assist with existing resources immediately, but there will also be a need for market expansion. In other words, we have significant capabilities in terms of utilizing our current resources and systems to support that growth. As such, we have much to offer in this regard, assuming it happens. Specifically regarding Mountain Valley, there is a sustained increase in demand on our system, and the incoming supplies will create synergies with Mountain Valley, regardless of whether it is completed as planned. While there are some differences because they address distinct needs, we definitely have the capacity to support 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.

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 we will always consider vertical integration as an important factor when determining if an asset is strategic. The aggregation of barrels, for instance, presents us with value and investment opportunities similar to Bluestem. Therefore, we carefully evaluate which assets we want to retain that could add value to our organization. Vertical integration plays a key role in that evaluation. This aspect often increases the value of our combined downstream investments, making those assets more valuable to us as a company than to others. I believe that's the best way to approach this.

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. In 2017, we experienced significant growth in Haynesville, and we anticipated that this level of growth would not be replicated in 2018 due to the high decline rates associated with the new production. At the start of the year, we did witness some growth, but by the end of the year, we noticed a decline in the Haynesville system, primarily attributed to Chesapeake's production. On a positive note, our team has been effective in acquiring new acreage from third parties apart from Chesapeake. This is promising for us, even though there hasn't been much change in our base dedicated acreage. We have successfully secured new business in that area, which should help sustain the volumes in 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.

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?

I will address a few of the questions. Firstly, regarding the Conway market, it's important to understand that if we reduce the difference between Conway and Bellevue, we benefit from that situation. You can consider this as a natural hedge for our business since we already own those assets. Therefore, if the prices for Conway products in the purity markets increase, it makes Conway and our services there more appealing. This is how we perceive the situation. As for whether it involves spec product or Y-grade, it really depends on the amount of additional fractionation capacity available at both ends of the process in terms of market dynamics. Additionally, we have contracts with third parties for Y-grade that include fixed margins.

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. I believe that when we start in 2021, we will be well positioned to take immediate advantage of that opportunity.

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. First of all, we have a total of seven years to consider the option, which gives us plenty of time. I want to emphasize that our investment with KKR pertains only to the GMP assets, and there is no investment in the downstream value chain outside of that joint venture. Therefore, it doesn't significantly impact the option value, since it will primarily be the cash flows from the GMP business that influence that value. However, I would like to highlight that our relationship with KKR is strong and well-aligned. The existence of this option keeps us focused on maximizing the value of the joint venture, which is a beneficial aspect of our collaboration.

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.

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.