Williams Companies, Inc. (The)

Please stand by as we're about to begin. 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 Michael 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 the generally accepted accounting principles and these reconciliation schedules appear at the back of today's presentation material. And so with that I'll turn it over to Alan Armstrong.

Great, good morning everyone, thank you John. I'm gonna start a little bit with the macro conditions that are continued 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 this 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 it's happened is what we expected to happen which is not just the US but all of the world is really starting to try to take advantage of the US'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 is 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 again came in at the top of our guidance ranges for key financial metrics. In fact, we achieved an all time record for adjusted EBITDA in 2018, even in the face of asset sales totally more than $4.6 billion over the past two and a half years and these transactions continue to reduce our commodity exposure and can continue to improve our leverage metrics for WMB and all the while, we funded growth over the past two years without the need for equity issuance. So as you may recall, we started 2018 setting delivery records on Transco which we've now in 2019, eclipsed once again during the record cold snap that impacted our markets last week and in 2018, Northwest Pipeline also hit an all time record for annual throughput eclipsing the prior record by 5%. So we are seeing the impact of all this increased demand showing up on our pipelines obviously.

We had a

timely and crisp execution on the critically important WPZ roll up transaction, reestablishing Williams as a simplified C Corp with investment grade credit. We continue to make great progress overcoming a highly challenging regulatory and permitting environment placing critical new Transco projects in service like Garden State, Atlantic Sunrise and just recently the Gulf Connector. And we continue to make progress advancing the extensive next generation of Transco fully contracted projects like Southeastern Trail, Rivervale South to market, Lighty South, Northeast Supply Enhancement Gateway and several other Transco projects that we've not gone public with yet. Late in the year we saw the beginnings of the accelerated Northeast GMT growth. We expect to continue for many years to come as the takeaway cloud finally has begun to lift this basin. We expected our ESG, sorry, we expanded our ESG disclosures on our website, kicked off the project to further expand our ESG disclosures in 19 and further strengthen our exceptional board of directors with two new appointments. We continue to exercise capital discipline passing up many opportunities but executing on others like our entry into the DJ basin which was funded through our exit from our legacy four corner position and we are now set for continued value creating portfolio optimization here as we begin 2019. And once again, despite increasing commodity price volatility in the liquids markets, our low cost natural gas based business strategy has us positioned well for further predictable growth here in 2019 and importantly today we are reaffirming the 2019 guidance that we provided in May of last year. So with that quick look back at a very busy 2018, let's move to slide two and take a closer look at our financial performance versus 2018 versus our guidance. Here on slide two you see that we've shown how we finished the year relative to our 2018 guidance ranges. Although our gap net income was affected by a large impairment on our bar net gathering system, you can see that adjusted net income exceeded the midpoint of guidance and our adjusted EPS which was at the high end of guidance showed strong growth in 2018 of 25% over the 2017 EPS. Despite selling 1.3 billion in assets that was not accommodated for in our plan back when we made that guidance, our adjusted EBITDA, DCF and dividend coverage ratio all reflected strong performance at the high end of our guidance range. You can see that our road cap expending came in about 300 million under guidance and that was primarily driven by shifts of capital out of 18 and now into 19. So when we get to our 19 guidance you'll see an uptick which was just the timing of that 300 million moving from 18 to 19. And finally with respect to leverage, you can see a niced out performance with year end leverage at 4.8. So once again, as was the case in 17, our financial performance was quite good as compared to our guidance. It was another year where we delivered on expectations including steady, predictable and growing cash flows while improving the balance sheet. On the next couple of slides, we'll quickly break down the major drivers of our financial performance for the fourth quarter and the full year, so let's move on to slide three. First looking at the fourth quarter gap numbers on the upper portion of the slide, we see that the year over year comparisons were affected by some large accounting entries which have been adjusted out of our non-gaps. Specifically in 2017, we had some large positive accounting entries related to tax reform and this year we have a large revaluation on our bar net gathering system somewhat offset by gains on asset sales. Looking at adjusted EBITDA in the lower portion of the slide we see that the nearly 1.2 billion of adjusted EBITDA was up a little more than 3% versus 2017 but up 9% if you normalize for revenue recognition changes in the sale of our four corner system. Looking at the bridge then, once adjusted for the revenue recognition changes and the loss of four corners which are shown in gray, you can see that our adjusted EBITDA increased almost $100 million where strong increases in our Northeast and Atlantic Gulf segments were somewhat offset by a lower quarter in the West. So it's really great to see the Northeast and Atlantic Gulf adjusted EBITDA numbers growing by 28% and 22% respectively. Atlantic Sunrise was the big driver of course for Atlantic Gulf and the Northeast saw about a 13% increase in volumes led by increases in Northeast Pennsylvania area but also we saw good growth in Southwestern Marcellus and the Utica area as well. So as we look at the results for the West, you have to be mindful of the pretty dramatic effect that the sale of four corners had on our reported gathering volumes. So specifically if you look at our analyst package you'll see that the West gathering volumes are down about 22% sequentially from 3Q and that our four year 2018 volumes are down about 4% from 17. However, if you exclude the four corners volumes then we are flat year to year and down only 3% versus the third quarter of 18. And of course that was impacted. We did have some freeze offs in Wyoming here in the fourth quarter of 18. Additionally, another big driver for the West in fourth quarter of 18 related to about 25 million unfavorable swing in the EBITDA of our NGO marketing business which was driven by the drop in the value of the inventory that we hold for Linefill primarily out West. The value of this near constant inventory changes every quarter as we mark this product to market prices from one quarter to another. So now let's turn to the four year 2018 results and go to slide four. Starting with our gap results in the upper portion of the slide we see that the larger counting entries we discussed on the prior slide are also driving the year over year comparisons. So again, tax reform entries, gains on sales of assets and impairment entries make it a little tough to see the performance of the ongoing business. So let's look at the adjusted numbers where these items have been excluded. First off, I just highlight again that the 25% growth in adjusted EPS which grew from 79 cents, sorry, which grew to 79 cents from 63 cents in the prior year. Looking at the bridge on adjusted EBITDA, you see in gray the effects of lost EBITDA from the Geissner assets we sold in 17, the changes in revenue recognition accounting rules and the loss of EBITDA from the Four Corners assets we sold in 2018. So once again, adjusted for revenue recognition changes and the lost EBITDA from sold assets, you can see that our adjusted EBITDA increased a little more than $300 million driven by strong increases in our Northeast and Atlantic Gulf segments. Growing volumes in the Northeast Pennsylvania and Southwest Marcellus and the Utica areas all drove the higher Northeast segment results. The Atlantic Gulf segment growth was again driven by Atlantic Sunrise, but a number of other projects that came on for a partial year in 17 also drove higher results in 18. So now let's move on to slide five and quickly recap some of the more significant and recent business developments. This slide showcases our recent accomplishments demonstrating strong project execution, continued permitting successes, operational excellence, and strategic transactions at the corporate level. Our teams have done an outstanding job of bringing key expansion projects into service like Transco's Atlantic Sunrise and Gulf Connector projects. One other project that I'll highlight on the list is our Norflat project in the Deepwater Gulf of Mexico. It's great to see some major new deepwater volumes coming mid-year as our Norflat project serving shells, appomattox fills, in the Eastern Gulf gets up and running. With the completion of these three projects, the majority of our project execution risk that is behind our growth drivers from 19 have been squared away. So on the permitting front, we have also seen great progress despite the difficult environment. Northeast Supply Enhancement received its FERC at the IS. This was a critical permitting step for a project that will support the conversion of heating oil to clean burning natural gas for New York City and the Long Island areas. Transco's Gateway expansion was another project that hit a key milestone, receiving FERC approval to expand existing bike lines to help New York and New Jersey meet growing natural gas demand needs in time for the 2021 winter. And most recently, our Southeastern Trails project cleared the environmental assessment hurdle at FERC. This is another example of Transco's tremendous advantage of having existing -of-ways in all of the right places. Operationally, our Northeast GMP segment increased gathering volumes by 13% from fourth quarter of 17 to fourth quarter of 18. And this was driven primarily by several gathering expansions of our Susquehanna system, as well as incremental takeaway capacity for Northeast Pennsylvania. We will continue to see volume growth on our Northeast systems into 2019 and beyond. Our Transco expansions help Transco deliver a record amount of natural gas, setting its peak day mark of 15.68 million decanthums on January 21st of this year. Transco also set a new three-day mark from January 30th to February 1st. The recent frigid conditions across the country are an important reminder of the vital role transmission pipelines play in delivering natural gas to keep millions of Americans safe and secure. And I want to take a moment to recognize the great employees that are there working behind the scenes to make that happen. It's not a simple task, and it takes a lot of dedication. And we certainly have that from our employees here at Williams. And speaking of records, our Northwest pipeline also hit an all-time annual record delivery of 820 trillion BTUs versus the previous annual record of 781 trillion BTUs. So a tremendous job by our Northwest team as well, as they overcome some major supply outages in Canada from third-party pipelines coming in, and we're able to manage around that and keep the heat on for our residents in the Northwestern area as well. Looking down the list, you'll see our BlueStem project, which we announced yesterday afternoon. Let's move to slide six to take a closer look at the newly announced project, BlueStem. We've got some good detail on this slide about this exciting new project, which will provide all new connectivity between vast Western NGL supplies and premium Gulf Coast markets. This strategic partnership provides for a great opportunity to really strengthen and expand our NGL transportation and fractionation business. We're pleased to partner with Target on this NGL infrastructure solution that creates an integrated network and integrated solution and a platform for growth for both parties. Expanding our NGL pipeline business to interconnect the Target strategically positioned Grand Prix pipeline will provide Williams and our customers with access to Mont Bellevue while opening up additional markets for Conway, attracting new volumes to both our Oberlin Pass Pipeline System and to Conway Fractionation and Storage Asset. And it will provide Williams with 80 to 120,000 barrels a day of firm access to Mont Bellevue. Additionally, this delivers a long-term infrastructure solution for NGLs from our OPAL, Echo Springs, Willow Creek, and our new Rocky Mountain Midstream systems in the DJ Basin, while also creating a platform for growth, offering us the opportunity to gain incremental downstream revenues as we expand our GMP business. We're targeting an end service date of the first quarter of 2021 for this project. Additionally, I would point out that in connection with this project, Williams will also have an option to purchase initially a 20% equity interest in one of Target's recently announced new Fractionation trains, trains seven or eight in Mont Bellevue. Our goal is to be well aligned with Target in maximizing the value of our collective assets in Conway and Mont Bellevue and the piping in between, and to offer attractive service offerings to our processing customers in the West. We expect our investment in these NGL logistics projects to be 350 to 400 million, with most of that spending that will occur in 2020. And now let's move on to the next slide for review our 2019 financial diets. As we previously discussed, we are reaffirming our 2019 financial guidance with the exception of growth capital expenditures. Of course, much has changed since we originally issued 2019 guidance last May. Specifically, we sold our large scale four corner system and entered into the DJ basin where the system there that we now operate was still in the early stages of its continuing expansion and development. And we and our producing and customers, of course, saw a 28% decrease in crude and NGL prices from August until year end.

Really,

the key point here is that the stability and predictability of our natural gas infrastructure focus strategy has allowed our 2019 guidance to hold in there very well, even as we've continued to optimize the portfolio and have seen a lower pricing environment for our producing customers. As a result, our 2019 guidance for financial performance remains unchanged and much of the project execution risk for 2019 is already put crisply behind us. ASR, Golf Connector, and our Norfolk facilities, as I mentioned earlier, are all now completed. So as I previously mentioned, we are revising growth capital expenditure guided from 2.6 to a range of 2.7 to 2.9 billion. And that's really just the timing shift of some of the amounts we didn't spend in 2018 that got shifted into 2019. The last thing I will say about 2019 is that we remain very focused on improving our credit metrics. To that end, we will continue to exercise capital discipline and to pursue portfolio optimization transactions, much like you saw in 2018. And of course, our strong cash flows and continued

string

of asset sales has allowed us to fund the equity side of our growth capital needs. So with that update, let's move on to the last slide, slide number eight, and wrap up, and then we'll take your questions. On this last slide, we again just laid out a few of the highlights from 2018, which was a very important year for Williams. It was a year where we beat guidance, returned to a simplified C-corp investment grade infrastructure company, completed the largest project ever on Transco, progressed on deleveraging the company, and made continued progress in optimizing our portfolio. Also on this last slide, we've summarized some of the things on our minds here for 2019. We look forward to another year of strong natural gas demand growth. We also look forward to showing how our business can deliver cash flow stability and predictability during times when the crude markets are volatile and sagging. We continue to be pleased with the opportunities we are closing on in the DJ Basin, thanks to the great work of our Rocky Mountain Midstream team that has done a great job of establishing themselves in the area as well with our customers up there. As an example, we just executed a new gas gathering and processing agreement for an additional 5,200 acre dedication that is fully permitted in the DJ. To support this development, we'll be expanding our gathering compression services in the Basin as we expect to open up additional near and long-term opportunities for our midstream services in the DJ. And we will have two new processing trains starting up this year as well, one of which is entering the commissioning stage and the other at Kingsburg for construction activities is progressing according to plan. We look forward to another year of advancing the important Transco projects that you are aware of and to introducing you to new opportunities for the nation's largest and fastest growing natural gas pipeline, and we look forward to another year of strong Northeast GMP volume growth. And last but not least, we will continue to de-lever. We will do this through solid execution of our business plan, which allows us to reinvest excess cash flows into new growth opportunities, but we will also continue to vigorously pursue portfolio optimization activities in support of this effort to de-lever. And finally, I also want to let you know that we've taken a look at the timing of our annual Analyst Day, and we'll be making a shift from the May timeframe to something later in the year. This major driver of this move is to really make sure that our Analyst Day follows up our annual board strategy session, which is in August, so we think that's a nice move to governance and simplifying our internal process to be able to roll right from our annual board strategy session into guidance. So with that, let's go ahead and turn it over for Q&A.

Thank you, and if you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question, and we'll pause for just a moment to allow everyone an opportunity to signal for questions. And we'll take our first question from Schneer Gershuni of UBS.

Good morning, Steve. Good morning. 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 a 20% stake in a frag? And also, any sense on what the stack rate would be to get the Y grade all the way to Montbellevue?

I would say, first of all, on the volume growth, yes, we did build in the flexibility in our relationship with Target to be able to expand our volumes as we need to, both on the transport capacity as well as on the investment in the Fractionator. 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. 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. I would just say on the rate, we're not gonna 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 Target 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. No, that makes sense. And given your new partnership with Target, do you see an opportunity to expand the relationship with respect to gas takeaway out of the Bermian, given that both companies have been exploring different gas takeaway solutions?

Yeah, hi, this is Chad Dameron. I would just say that we continue to, I think if you look at our recent announcement with the Brazos mainstream system in the Bermian, we continue to focus on the Bermian, and I would just say we're gonna continue to be disciplined, and there have been two projects that have been announced coming out of the Bermian 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 would move to the Gulf Coast, and I would say that we are likely, if we do move forward with a 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 -to-apples basis, you have some rollover from 2018 into 2019, and you've just announced a new project, so it would kinda seem like on an -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 the subtle changes.

Yeah, 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 Let's Driver and 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 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.

All right, that makes perfect sense. Thank you very much, guys, really appreciate the color.

If you find that your question has been answered, you may remove yourself from the queue by pressing the star key followed by the digit two. We will take our next question from Christine Cho with Barclays.

Good morning, everyone. Just wanted to make sure I understand this agreement with Targa. Are the economics here really gonna be driven by the volume growth out of the Rocky Mountain mainstream JV, and also any color around when you expect to achieve that ebidommal bulliflux times, and what sort of volume growth we should assume is underpinning those economics?

Hi, Christine, it's Michael. 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 Blue Stem Pipeline eventually. As you know, we've got the partnership on the OPPL system, and we'll continue to move those Rockies barrels down the OPPL system to Conway, and then further south on Blue Stem. And with our 2021 in-service date on Blue Stem 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 six times multiple on that. And really, a lot of that's 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 six times multiple pretty quickly.

And just to clarify, the volumes coming out of your existing plant, 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 gonna 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 slottish 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 from where we had thought it would have been last year. And that's really coinciding very nicely with the completion of Oak Grove TXP2. 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 TXP2 at Oak Grove comes online. So we anticipate certainly filling TXP1 this year, and TXP2 will start processing gas very shortly after that. Got it, thank you.

Thanks, 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 the Checkmark Pipeline and some other projects that we have to get completed before we can bring those new 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 drill 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 on volume commitments whenever we agree to go deploy capital there at those processing facilities. We have MVCs 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.

Hi, good morning. Maybe just kind of picking up on that last point there. Thanks. 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 impact in your footprint because it seems like some of the guys behind your systems might be taking a bit of a different tack than others there. If you could expand 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 Michael can fill in with some details if required. First of all, I think not all producers up there created equal, and certainly not all acreages 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 the Bradford County area continues to grow very rapidly for us as well. And so, as Michael 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's been some folks pulling back a little bit on volume growth, as Michael mentioned, those MVCs that people have made to us, they're gonna work hard, obviously, to fill those up. They're being very successful with the production back 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 still feel very confident in that 15% CAGR that we put out earlier based on the detailed work that we do with the producers. I would say, as I've mentioned earlier, probably one more positive thing about that growth that's occurred is the Encino acquisition from Chesapeake on that Utic 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 grow. So that's a really big positive for us in terms of offsetting some of the declines that existed out

there. That's very helpful, thanks. I just wanted to turn to Atlantic Gulf here real quick, and I had quite a nice quarter there. I was wondering, is this kind of something that's run right level for you guys, or is there still more kind of sunrise? It's not fully baked in for the quarter, and you can continue to see growth there, or how should we think about that segment?

Yeah, this is Michael again. I would say the majority of the quarter, we saw the Atlantic sunrise revenues in there. It came online October 6th 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 on October 6th. So basically, you would see the fourth quarter having the majority of the revenue in there for Atlantic sunrise. If you recall, it's a revenue payment, or sorry, a capacity payment. And our 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. That's helpful, that's it for me. Thank you,

Jeremy.

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

All right, great. Just one thing on that last point on the Chesapeake, Utica Acres now with Encino, can you frame any better that rate of change you're expecting from an asset that was in decline now sounds like more activity, just any notable color from early days with Encino in place?

Well, they're still on their process deciding how aggressively they wanna go after it, but I think the big shift, of course, is the available capital that Encino has through the Canadian Pension Fund. So they're anxious to put that capital to work and drive the returns on that. So it takes a while to get ramped 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 gonna 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's what will drive that. And

of

course, they're very efficient. They've got a lot of a team that was already existing there, very efficient operators, and with three rigs, they'll be growing pretty rapidly in that area.

Okay, great, thanks. Just one more on Gulf East. If you could just clarify a little on Appomattox, sounds like coming on a little sooner than expected. If you can just remind me the status of the Northlit pipeline option to you, and just in general what you're expecting from the ramp in that area this year, thanks. Sure, thank you, TJ.

Yeah, we have completed all of our work, and the pipeline option then 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 decisions to exercise that. So really it's 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. They've done a great job, really great execution on Shell team on being so far ahead of schedule as to 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 fields proper, but a lot of new work going on by both Shell and other producers in the area and acres around that would be nice highbacks in the north with our infrastructure out there. So I think that's gonna 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. Okay, thank you.

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

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

Well, I would just 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 mid-continent 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 were 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 gonna be picking up other barrels in

that area. Okay, thank you. 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?

Yeah, on our system, it would be, it would be, 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, 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, for instance, in the Rocky Mountain area, we'll 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, thanks. And then just, there's a word in the press release that I wanna just try and understand. You say there's an initial 20% option on one of the fracks. I guess that implies that there will be additional options or potentially, am I hearing that right? Yeah,

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

from that area. Okay, great, that's helpful, thank you. And I guess maybe just one on the leverage, it seems 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 gonna be more opportunistic?

No, I would say we're constantly looking at optimizing our portfolio, and we are working really hard, I can tell you the entire team with the board 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 go on to say even without that though, again, remember we're generating a rent around $1.2 billion of excess cash, even with the track of dividend growth, and we can use that cash even on new invested dollars, so we actually are deleveraging even with investments in new projects because we're putting so much of it with cash. So again, asset sales will enhance and speed up the deleveraging, but we're deleveraging even without asset sales. Right, right, got it. That's it for me, thanks very much.

Thank you.

Next we'll hear from Michael Bids of Goldman Sachs. Hey guys, 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 y'all have faced in terms of building pipelines into New York and dealing with kind of state level interveners or stakeholders.

Michael, this is Michael. We'll 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 for their 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 have 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 and that allows the Corps of Engineers to issue what's called a transfer or permit and FERC takes that into consideration in order to give us a notice to proceed with construction. So we expect all of 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 the potential for settlement or whether you think this goes the full litigator route.

Right, I can give you an update on that as well. So we would expect to see what's called the top sheets from FERC in mid-March and that's really their staff's reaction to our filing and basically provides the sideboards, if you will, of what we can then go to settlement negotiations with FERC 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.

Got it, thank you guys, much appreciated.

With Chewie Brothers, we'll hear from Greg Shear.

Good morning. Morning, Greg. 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?

There's really a couple of things, this is John Chow, 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 a quarter 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 type calculations because we're using a different rate for our adjustment items, our normalization items. We're using our standard annual rate of 25% instead of what it actually blended to. It's probably confusing but I just asked you to reach out to our IR team, I think they can walk you through that but it's really those two things, the significant unusual items and the tax provision adjustments that are done in the fourth quarter.

Thanks John, yeah it looked like the EBITDA was in line but the adjusted DPS a little off and that explains a lot. Alan, in your prepared remarks you talked about several other Transgo projects not gone public with yet. Can you give us a picture of the range of opportunities in terms of size and maybe any updates on the Transgo project one that was heavily foreshadowed on the 3Q call?

Yeah sure, first of all on project one, remember we had two there, we had project two which was Lighty South which is moving ahead very nicely and fully contracted. Project one we continue to work with the counterparty, primary counterparty on that and I would just say 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. But we remain very confident in the fundamentals and the drivers behind that project. I would also say that we have several other new projects that are well on their way to development, a lot of strong interests that would continue to alleviate capacity constraints out of the Northeast PA area and so we're pretty excited about that and that also helps expand into 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 six and so we've got several projects that are pointed at that and again the interest in those projects is very strong.

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

Absolutely, yeah and I'm not gonna call it project three because we've grown weary of that but it is a nice project flowing right behind the other two.

Okay and here's a little bit of my bigger picture question. I understand the Barnett is not a 2019 headwind but I wanna get some sense of the longer term gives and takes in GNP. If we look out to 2021 as you target a 15% pegger on Northeast GNP volume growth off 2018, depending on assumed margin growth per end, is it reasonable to assume that Northeast GNP that can rise 600 million to 900 million plus off 18 levels and then with Barnett maybe be a headwind of as much as 150 million?

Yeah, we're not gonna provide guidance individually on Barnett but I would say this Greg, the lowering or the impairment we took on Barnett is, you know I don't wanna drag everybody through all the accounting details but we were, that asset was held according to the undiscounted cash flows on the asset 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 spread, so every year we would 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 receive as well as the actions of the, what we estimate 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 was the way it was marked earlier. So it was, I said it 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 valuing 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 valued it.

So nothing's

really changed all that much there other than again the Permian gas supply. If the Permian pipelines all get filled adequately and we see 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. And

I just add to that, if you go to the third quarter of 2017, we impaired our mid-continent asset then it was the exact same scenario that was set up. There wasn't a material change in the actual EBITDA generation for the mid-continent assets but the gross cash flow dropped enough to make us take it from a historically high carrying value down to its fair value. So same's happening with the Barnett, we don't see any meaningful change in the EBITDA stream but it was just enough to trip that right down from carrying value to fair value.

No major change even looking out, say to 2021.

No, not really. It's 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 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 GNP gaining say 600 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 50 to 55 cent EBITDA per MCF range that we've talked about earlier. And so with the volume growth and with that kind of margin improvement answers, yes, I'm not crystal clear on the timing that you're laying out just to be very fair just having thought through that versus that amount. But in terms of what we laid out here at Analyst Day, we were feeling very good right now about both the volume growth and the margin growth that we're experiencing. Great, thank you.

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

Hi, good morning. When you look at, I guess, the annualized Q4 numbers for your adjusted EBITDA from equity investments, that would kind of suggest a much higher run rate versus your 2019 guidance of 825 million. And I guess if you assume contributions from Jack Wohl, 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, you want to? Well, offhand, I don't know that 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 DDNA expense, is that correct, going forward?

If there is an impact on cash flows, it's very minimal on Barnett. So yes, it's just that it's an uplift, or it's an improvement or reduction of DDNA, 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?

Yeah, that sounds right, yes. Okay, great, thank you.

Next up is Jean Ann Salisbury with Bernstein.

Good morning, just a couple quick ones from me. So it seems like Mountain Valley and the Atlantic Coast Project have hit some difficulties. In the theoretical events that one of these projects is ultimately canceled, could Transco address that demand with new laterals, 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 using existing -of-way. But not fully, so said another way, some of that market expansion to 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 -of-ways 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 is so much continued growth in demand on our system that those supplies coming in, we're gonna be, we'll have synergies with Mountain Valley whether it gets built as planned or not, we would have quite a bit of synergies there with that system. So I would say they're a 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, the Bluestem EBITDA is all incremental from the EBITDA that you'd expected on the initial discovery deal. I assume so, but just wanna make sure.

Yeah, 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. Okay, that's all for me, thank you.

I would say this though, when you collectively put in the investment on Bluestem with the investment in the Rocky Mountain Midstream assets, we still accomplish six times multiple, even the combined investment when opening that system is fully up and operational.

Next up is Colton Bean with Tudor Pickering, Holt & Company.

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

No, I would say that we've always looked at 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 wanna hold when we're in the business, 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 it. Got it, that's helpful. And then just to touch briefly on the West, so you mentioned gathering volumes and that of the four corners adjustment there, down around 3% queue on queue. Just interested in what you're seeing on the Haynesville system and maybe a longer term outlook there as well.

Yeah, you know, 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 there was so much new flush production and the decline rates on that new flush production is pretty high. So, and 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'll 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.

Got it, all right, I'll leave it there. Thank you very much.

I'm Jeff Rees, we'll hear from Christian Olofie.

Hey, good morning, Allen. Thanks for taking my questions. Not sure if this one's for you, Michael 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 have made clear the advantage of gaining better access or greater access to Bellevue through target systems, 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 for that?

I don't know, that's a lot of questions, but I'll take Chad back on here. Let's see, first of all, on the Conway market, yeah, 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 spec product prices come up in the purity market, 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 two to five years to be up that could transition to this new collection of Williams-Targa assets, or is it a long term? Yeah, 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.

Oh, okay, great. Thanks for that. I guess switching gears and just a quick follow-up from me on one of Jan's earlier questions. You had noted, I think, when you entered the DJ JV with KKR that you were retaining some options to acquire from KKR additional interests. And so I'm wondering, Michael, you had said that you contemplated other NGL solutions as part of that investment. I'm wondering now that they've maybe 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.

Yeah, I would just say, first of all, we've got seven years, I think, total on that option. So long time to 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, they're proper. So it doesn't really affect so much that option value, if you will, because it's really just gonna 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, it's 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. 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 we've been successful, new connections there that pretty attract returns. If 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 for us in the future to exercise that option.

And so I guess final point on that then, John, assuming 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 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.

All right, wonderful, thanks for the time. Happy Valentine's

Day. Thank you, you

too.

It appears 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 of the way the teams are operating. And we like the macro conditions that are set up ahead of us as well. So going very good about both the current 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.