Good day everyone, welcome to the Williams Partners first quarter 2018 earnings conference call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, head of investor relations. Please go ahead.
Thanks, Christina. Good morning, thank you for your interest in The Williams Companies & Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include press releases and related investor materials, including the slide deck that our president and CEO, Alan Armstrong, will speak to momentarily. Joining us today is our Chief Operating Officer, Micheal Dunn, and our CFO, John Chandler. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks, 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. With that, I'll turn it over to Alan Armstrong.
Great. Thank you, John, welcome everyone. I plan to keep the remarks pretty brief today due to our upcoming Analyst Day, where we're going to provide a much more in-depth review of the business. We're really looking forward to highlighting a lot of things that are going on. I would say here at a high level, the quarter was right on plan. We met expectations, we continue to remain on course and anticipate significant growth as we look toward the second half of this year and into 2019. Our strategy of focusing on connecting low-cost natural gas supplies to the fastest-growing demand centers allowed the organization to leverage our solid foundation of advantaged positions to deliver another predictable quarter of broad-based growth. Once again, showing year-over-year improvement in adjusted EBITDA in each of our business segments.
While we now have a long string of adjusted EBITDA growth posted, we're most excited about what our intense focus on strategy will produce for us in the long term. This focus has allowed us to continue to identify, develop, and contract for new opportunities at a higher-than-industry average returns. This is going to drive improvement in ROCE and shareholder value for many years to come. No one is as well-positioned as The Williams Companies to capture the accelerating growth and demand for U.S. natural gas. We look forward to updating investors about our significant achievements and future plans at our Analyst Day event on May 17th. For today's relatively brief call, we're going to hit just a few things here. First, a recap of our performance for the first quarter of 2018.
I'll hit a few highlights that we saw in terms of strong execution in the quarter, that we're delivering across all of our business segments. I'll drill down a little bit into the business segments. Finally, I'll continue to outline the key topics that will provide a deeper dive into our Analyst Day event. For now, let's move to slide two and review our results for the first quarter. First of all, I'll say I'm pleased with the continued project execution and operational performance our teams delivered during the first quarter of 2018. Looking to our GAAP results, the Williams Partners net income was $360 million, reflecting a $274 million decrease from first quarter of 2017. The higher net income in 2017 was driven by a successful asset sale program that we executed in 2017.
The largest driver of change was the absence of a $269 million gain that we booked on an asset sale in the first quarter of 2017, the absence of margins from the Geismar Olefins facility, which was sold in July of 2017. That was the bulk of the $59 million increase in commodity margins that you can see posted in our numbers. $269 million on the gain and the largest portion of that, $59 million of commodity margins. Moving on to non-GAAP measures, adjusted EBITDA was $1.12 billion, an increase of $5 million over the first quarter of 2017, was up $53 million or 5% for the partnership's current business segments over the same period in 2017.
This was driven by $58 million in increased revenues from our Transco expansion projects being placed into service in 2017, another $11 million of higher fee-based revenues in the Northeast Gathering segment. This was partially offset by the $23 million decrease in proportional EBITDA from joint ventures, I'll hit on that a little more here in a minute. All three of our current business segments showed year-over-year improvement in adjusted EBITDA. Let me drill down into the drivers for each of these areas. First of all, in Atlantic-Gulf, we saw a $13 million increase in adjusted EBITDA. The fee revenues on Transco were up 16%, due in large part to the many fully contracted expansions placed into service during 2017.
We did see higher expenses compared to 1Q of 2017, expenses actually decreased by about 10% from the sequential quarter in the Atlantic-Gulf segment. The larger offset came from Discovery, where the depletion of Exxon's prolific Hadrian wells drove the JV EBITDA down about $29 million in quarter, that was as we projected in last quarter's earnings call. We'll see that impact continue to taper off as those wells depleted down through the third quarter of last year. The completion of Atlantic Sunrise, with about $105 million per quarter of incremental revenue for Transco, will be a significant contributor to the growth we anticipate in the latter half of this year for the Atlantic-Gulf segments. Moving to the west.
The west increased adjusted EBITDA by $17 million, despite some large impact from revenue recognition in this comparison, the west continues to produce stable results from a broad range of customers and supply basins. In fact, gathered volumes were higher in nine of the 10 franchises first quarter of 2017, the one area that was lower was the Barnett, which showed about a 5% annual decline from the same period last year. The west continued its strong record of reducing expenses as it showed another decrease in expenses from first quarter of 2017 and overcame the loss of EBITDA associated with a gathering asset that was sold in 2017 and from the new lower rates that we are recognizing on Northwest Pipeline. Looking forward, producers are starting to respond to higher oil and NGL prices.
While gas gathering volumes were up 8% for the west, processing volumes increased 9% on a year-over-year basis, that's on a plant inlet gas basis. We are seeing additional producer activity in liquids-driven plays like the Wamsutter area in the Wasatch-Uinta Basin in Wyoming, the Eagle Ford, and now emerging is the Turner formation in the Powder River Basin. All of these areas should drive volume growth for the balance of the year. Now turning to the Northeast Gathering segment. The Northeast showed the largest year-over-year improvement of $23 million or 10% in adjusted EBITDA. The improvement was driven primarily by 5% increased gathering volumes and increased gas processing business at our Ohio Valley midstream complex in West Virginia, where we actually saw inlet gas processing volumes increase by 27% and NGL production was up 34% over the first quarter of 2017.
This was driven by both new drilling and new contracts being won by our team in Pittsburgh. While managing these volume increases, the team worked hard to keep costs flat on a year-over-year basis and actually reduced operating expenses from the fourth quarter of 2017 to the first quarter of 2018. Results for the current year also benefited from an $11 million increase in proportional EBITDA of joint ventures. This was led by the Bradford County JVs that we increased our ownership in during the first quarter of last year. We are seeing a significant ramp-up in requests for system expansions as the Atlantic Sunrise and other key takeaway infrastructure serving the Northeast begin to take shape. We expect significant growth in volumes and EBITDA from the segment by the fourth quarter of 2018. We really are seeing a lot of activity going on.
Our teams are staying very busy responding to requests from producers for expansions on our systems right now. Now looking at DCF. Distributable cash flow continued to increase by 5% versus the first quarter of 2017, allowing us to meet our guidance and distribution increase of 5%-7% annually while maintaining a strong coverage ratio. Our coverage again this quarter was 1.33 at the partnership level and of course on an economic basis, then is much higher at the WMB level. Now turning to slide three. We recap some of our recent achievements here as we continue to build long-term predictable growth in the business. As I've said earlier, we'll discuss our projects in greater detail at our May 17th Analyst Day event. Already this year, we've managed to set new delivery records on our Transco system.
We also have started construction on the Gulf Connector, a $475 million Gulf Coast LNG delivery expansion. That's an expansion that goes from Louisiana into some of the large Texas LNG facilities, namely Freeport and Corpus Christi. We placed phase 2 of the Garden State Transco expansion into service and placed additional gathering expansions into service in both our Susquehanna Supply Hub and our Wamsutter Gathering System in Wyoming. Finally, just last month, we established new volume records on our Susquehanna Supply Hub. This was driven by the expansion projects that we placed into service in that area, and Northeast volumes continue to increase as planned. West volumes increased in nine of the 10 franchises as we continue to see growth in many of the areas of that segment.
We also filed our FERC application for a fully contracted Southeastern Trail expansion project that'll serve growing demand in the Mid-Atlantic and Southeastern markets. Again, another one of these projects which were unique on our system that is demand-driven projects, and the contracting for that is being driven by markets, not by producer push. On the 1.7 Bcf a day Atlantic Sunrise project, 90% of the pipe stringing and welding for the pipeline construction portion of the project has now been completed. Hydrostatic testing has commenced on certain segments of the greenfield pipeline, and we have begun making a very large number of tie-ins along the line. Despite an extremely wet and extended winter, we continue to target mid-2018 for placing the project into service. I will tell you that is thanks to some very dedicated and hardworking employees, and some terrific planning by our team.
Really has been very difficult conditions up there, the team has continued to overcome that, is making great progress on putting that project in service. All of the items I've highlighted here reinforce our confidence that we'll see good operational performance and increasing growth in the second half of this year, which sets us up for an even stronger 2019. Moving on to slide four. As I mentioned at the beginning of the call, I look forward to visiting with many of you at our Analyst Day event on May 17th in New York. We will certainly highlight our natural gas strategy and how our leading positions uniquely enable us to connect low-cost supplies to the robust demand for natural gas that we are now beginning to realize on our systems.
We will also look at our extensive list of attractive projects spanning our operating areas that are currently in execution or under development, these give us great transparency towards predictable growth over the not just in the short term, but very much in the long term. We are really excited to see the way our pipeline for growth is continuing to fill in, we'll highlight that. We'll also address the recent FERC action on regulated pipelines held by MLPs. Finally, many elements are coming together which provide great transparency to our 2019 growth, and we look forward to highlighting the key drivers of this significant ramp-up that is now before us.
Again, I'm very pleased with the operational performance and project execution of our teams, and the year-over-year growth in our continuing business segments reflects the very solid quarter of results that Williams and Williams Partners delivered. Operator, let's take the first question, please.
Thank you. 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. We'll take our first question from Jeremy Tonet with JPMorgan.
Good morning.
Morning, Jeremy.
Appreciate that you might wanna wait for the Analyst Day on this, but just wanted to touch base on the FERC and see if there's anything additional that you could share with regards to the recent decision. If collapsing the structure could mitigate some of the impact there, and if so, would you be able to quantify that in any sense?
Yeah, I would just say, Jeremy, just like we've said previously, we're very confident in our ability to manage that through various structures. We don't expect any impact to our guidance. Really nothing new on that to offer you other than we are very confident in the various structures that we have available to us to manage that.
Gotcha. Thanks for that. I think you touched on a bit on in your comments, but the west stepped down four Q17 into one Q18. I was wondering if you might be able to decompose a bit more as far as some of the drivers there. Appreciate there was the rate case with Northwest Pipe, anything else you can kind of share there?
Sure.
Yeah, I would say the, probably the biggest impact in the west was that Northwest Pipeline rate case where we had a settlement with our customers, that did take the revenue down. I'd say that's probably our biggest impact in the west there. On gathering volumes, keep in mind, although sequentially we were down, we were very strong in Q1 2017 to Q1 2018. I would just say on that, we had very strong performance in Q4, primarily in the Haynesville. Naturally, that's a tough comparison coming off the fourth quarter compared to the first quarter when we had such strong results at the end of last year.
Just in some of our gathering areas, surprisingly, we didn't have any weather impacts in Wyoming in our traditional cold weather areas, but we did have some Eagle Ford and Haynesville winter impacts in Q1 that hurt our volumes a little bit. It really wasn't too bad this winter.
Jeremy, one other thing I'd add to that point, too, in the west. We talked on our last. This is John Chandler. We talked on our last earnings call about the new revenue recognition standards. In the west particularly, that's where we've had a number of previously settled MVCs and other things where we received prepayments. Under the new revenue recognition standards, we're extending the amortization of that over a longer period of time. There was a, just a pure book step-down. It wasn't really a cash step-down between the fourth quarter and the first quarter, probably to the tune of $20 million-$30 million between those periods. There was a big step-down related to non-cash revenue recognition items.
Great. That's really helpful. Thanks. Then just one last one, if I could. In the northeast, could you provide a bit more color, I guess, as far as where you see gathering volumes shaping up over the balance of the year? Any more color that you can share there as far as producer activity behind your systems?
This is Micheal Dunn. I'll tell you, in a couple of our areas, let's start in the Ohio Valley area, the Ohio River area. We're seeing a lot of growth there on the west side of the system, bringing in volumes from Southwestern EQT and likely Chevron this year. A lot of activity in regard to our processing facilities there. Our Fort Beeler, we're at capacity on that. That's between 550 million and 600 million of processing capabilities there, and Fort Beeler's full. We're expanding Oak Grove. If you recall, Oak Grove has one train there, and right now we're putting train 2 in. That will go in service next year, and likely train 3 following shortly after that. We're seeing a lot of activity on that side of the system.
Shifting more to the Northeast Pennsylvania area, we will be seeing a lot more activity coming from the Susquehanna Supply Hub as well, with Cabot ramping up to fill their volumes on Atlantic Sunrise. Some of that volume will be a shift from where they're delivering gas today on other interstate pipelines, but they'll also be bringing on incremental production there. They had no net Marcellus wells come online in Q1. Right now they're anticipating 20 net Marcellus wells in Q2 and about 60 in the second half of 2018. All of that volume comes on our Northeast gathering system. That definitely will be ramping up to fill Atlantic Sunrise, and they've stated publicly that they intend to fill that volume nearly from day one, as soon as we're able to bring the project online.
That's great. Good to see continued growth in the Marcellus, even despite what we hear about in the Permian. That's encouraging. Thank you for that color.
Sure.
We'll take our next question from Christine Cho with Barclays.
I wanted to start on the FERC actions that took place. Hypothetically, in the event you guys do a transaction where there's a step-up in basis in the assets, would that eliminate or materially reduce your accumulated deferred income tax balance for your pipes? Just trying to get a sense of the impact a transaction like that would have on your rate base calculation for your FERC assets.
Yeah. No, we don't think it would eliminate that, no.
Okay.
Just to be clear, though, at the same time, if you think about kind of the two steps to our accumulated deferred income tax, there's of course the regulatory liability we booked at year-end relative to going from 35 to 21. That would still be subject to possibly providing rate relief back to the shippers. That was part of our guidance when we talked last quarter, that we believe we could still file for a rate increase even with that in mind on Transco. As it relates to the March 15th filing, we'll still be a corporate taxpayer, and we believe that deferred tax liability will still be out there and still be payable by the company. We don't feel like that has any rate implications, and at the same time, don't believe it would be eliminated either.
Well, if you, I guess, keep the pipeline in the MLP, and you have to take it from 21%-0%. Are you going to have to book more into the regulatory liability?
Yeah, I think that would be the outcome if at the end of the day, it were in the MLP, you would have an additional regulatory liability, yes.
Okay.
I would also say, though, that's subject to the notice of inquiry. It's not completely clear yet how the FERC intends to handle that. Various regulated entities are responding to that NOI, I think it's still subject to that. To the extent that the FERC follows kind of the same approach that we did on the 35%-21% move, yeah, you could expect that to happen.
Okay. Earlier this year, it was out that Caiman was marketing their interest in Blue Racer, you guys seemed to indicate that buying out their stake wasn't of interest, but getting control was, maybe to gain some operational synergies. How do you think about this now that Dominion is out there potentially selling their ownership and that one party could collectively buy both their stakes, which I think add up to over 70%?
Yeah. Well, Christine, we won't get into the details of that, we do have rights related to that type of transaction, particularly as it relates to the Caiman interest. We're not too concerned. Nothing's really changed in that regard just because of our rights in the case of the sale or transfer of interest there.
Okay. Lastly, can you give us some more color on the denial for the water permit for the Northeast Supply Enhancement project, what the next steps are and what that does to the potential in-service date?
Yeah, Christine, I can do that. This is Micheal Dunn. During the past year, we have been working very closely with the New York State Department of Environmental Conservation to satisfy the conditions necessary for issuance of that water quality certification. They did inform us prior to the denial that they needed additional time to complete their review. There's a statutory period, and you probably recall this one-year period that if they don't act, there could be a waiver be deemed to occur. In order for them to allow more time for their review, they did deny that permit. We certainly have every right and every intention to refile that permit and the full support of our customer, National Grid
Assuming we still get the water quality certification and all the other permits and FERC approvals in the same timeframe, it really wouldn't have any impact on the schedule. We do intend to refile that in the next several weeks, and assuming that New York continues its review, which we think they will, we will be able to continue on with the project schedule. It's a critical project for New York City. National Grid certainly needs it in order to continue converting the fuel oil that's burned there into natural gas units. And right now, our project would displace about 3 million gallons of heating oil every year, and that would reduce CO2 emissions by up to 2.4 million tons per year. We certainly think it's a much-needed project, and National Grid certainly needs it to continue their conversion activities there in the Northeast.
Great. Thank you for the color.
We'll take our next question from Colton Bean with Tudor, Pickering, Holt.
Morning. It looked like there was some solid growth on the volume front for the Northeast equity investments, but the proportional EBITDA lagged a bit. Any color on the primary drivers there, whether it was maybe Blue Racer or Utica East, or just what caused that variance a bit?
Yeah. Most of the volume growth there was on the Bradford JV. You are right, the Cardinal and UEO interest, there were declines on the rich gas Utica volumes there. That had impact on that joint venture. Primarily, it was Bradford increases offset by some Utica rich declines.
Okay. Just a lower margin dry gas there, a bit of a mix shift.
That's exactly right.
Got it. Okay. I just wanted to follow up on Jeremy Tonet's question on the west.
Just to be clear there, Colton Bean, sorry. Just to be clear that we did see EBITDA increases on Bradford, we'd have had lower rates there, but you're right. The Utica rich, we have higher margin on, and that is where we saw the lower EBITDA.
Got it. Appreciate that. To follow up on Jeremy Tonet's question on the west, if you could just give a little bit more detail there. I think you mentioned the weather impacts in the Eagle Ford Haynesville. Any way to quantify that? It sounds like it was fairly marginal. Or have you also seen any sort of shift in activity, maybe from producers actually transitioning rigs away from the Haynesville to liquid-rich basins, whether that be Niobrara or your Powder River assets? Any comments there would be helpful.
Yeah. I'd say the winter impacts there were very minimal. I just mentioned them because it's unusual to have those winter impacts in those areas for us. I would just say the Haynesville ramp-up was very significant last year for us. If you recall us talking about that last quarter. The rig activity there is still there. I think Chesapeake Energy talked about one of their wells that they brought online just this week in the Haynesville, which is a pretty significant lateral length there. We would expect pretty significant production on an initial production rate from that well. We're still seeing activity there, and we expect them to have significant activity in the Eagle Ford, as they talked about on their call yesterday as well.
There's also a lot of activity occurring in the Powder River Basin with a lot of producers up there seeing some interest in that area, and we're fairly well-positioned with our partnership there with Crestwood to take advantage of that as those opportunities arise.
Yeah, I would just add to that. In Eagle Ford, we also had an outage or a planned turnaround at our Dilley gas treating facility, tower gas treating facility there, and I think that was about a week of outage there. That is an unusual event. It was planned, but it did impact the quarter. I think on the Haynesville, as we've mentioned earlier, anytime you have these big new wells coming on like we saw a lot of in 2017, you've got a big decline to work off in the near term. The fresher the production, the more immediate decline. There is adequate activity out there, and we are seeing that pick back up here as we get through the winter. You always have kind of a little bit of a lull during the winter.
At the end of the fourth quarter, or of course, the first part of the first quarter. We'll see some of that pick back up. We are definitely seeing more rigs move over to the oil and rich gas areas right now, no doubt about that.
Got it. I guess just the last one. You hinted at some updates to the CapEx budget at the Analyst Day. I understand if you'd prefer to hold out most of the details. Just any indications as to whether those are primarily adjustments to the scope of existing projects or whether we should expect to see some additions to the backlog?
Yeah. It is a lot of new projects, I would tell you. A lot of it's more of the same, if you will, in terms of incremental demand for services in the Northeast and some new opportunities along the Transco system that are driving that.
Got it. Thank you very much.
We'll take our next question from Ted Durbin with Goldman Sachs.
Thanks. Just coming back to the FERC items. I know you're going to touch on the Analyst Day, but I think on your last earnings call, you said you wouldn't see downside into the rate case from going to a 21% rate on the income tax allowance. If you keep Transco in the MLP and you go to a zero tax allowance, do you have a refreshed view on the potential for whether that would be a reduced tariff or what kind of impact that would be using a zero tax allowance?
I would just say, we have plenty of structures to use, and we don't intend to contemplate that path. There's plenty of other structures that we would employ. I do not expect us to file a rate case without the tax allowance in.
That makes sense. If we do, sorry for the hypothetical, but if we do stipulate that one of the ways to do that is to roll up WPZ into WMB, I guess, have you previewed what that might look like with the ratings agencies? Have they given you any sense of what you would need to be at from a leverage perspective to be investment-grade at a consolidated entity?
Not really on that front, I would tell you this. I've had an opportunity to talk to the rating agency. Obviously, having been new here at Williams, this is John Chandler again. Having been new here at Williams, and now eight months in, I've had an opportunity to talk to the rating agencies just to kind of reaffirm my view of what is BBB, Baa2. I think it's consistent with what I've felt it is, somewhere inside 4.75 times and ultimately down to four and a half times. I think, as a long-term view on a consolidated basis, we desire to be BBB flat, Baa2. It's certainly clear in my mind today, too, that we may not be totally at that level, but we're certainly investment-grade on a consolidated basis. We're certainly at Baa3, BBB flat with a lot of capacity there.
Got it. John, just to be clear, those numbers you're quoting, you tended to, I think, lift the numbers versus the reported EBITDA by about a quarter of a turn. Is that fair?
That's right. The numbers I'm referring to are rating agency-adjusted.
Okay, perfect. Yep, understood. Last one for me, just on Atlantic Sunrise. Great to see the progress there. What are the key items left, milestones that you need to hit to hit that sort of mid-2018 in-service date that you've discussed?
Right now, as Alan said, we had a tough winter up there. Anybody that's residing in the Northeast knows how tough it was, and a lot of snow and rain on the right of way. The contractors have done a great job progressing through the winter. As Alan indicated, we're looking at a mid-2018 in-service. Compressor stations are coming along and looking very good from a schedule standpoint as well as the pipeline. Right away, we've got four of the six horizontal directional drills completed. The other two we should have pulled back here in the next two weeks on those. We are starting hydrotests. It's really weather dependent now.
We're targeting an in-service date, and we're plus or minus weeks on either side of that date right now, and it's really all driven by getting some good weather in the Northeast, and we'll make some really good progress as soon as the weather breaks up there for us.
That's perfect. That's it for me. Thank you.
Thanks.
We'll take our next question from Darren Horowitz with Raymond James.
Hey, guys. Good morning. Just a couple quick housekeeping questions from me. The first, looking at the sequential change in O&M, it was down nominally, and you guys mentioned the asset sales, but it looked like it decreased about 100 basis points. Thinking about it on a % of total segment revenues, it was around 16%. Is that the right way to think about things as we progress through this year?
Yeah. Sorry, Darren, could you repeat that? We didn't catch the first part of that question. Sorry about that.
No problem. Yeah, I was just referencing, Alan, that O&M obviously is down nominally, sequentially, but as a percent of total segment revenues, it looked like it dropped about 100 basis points from 17% in the fourth quarter to 16% now. I'm just wondering from an O&M perspective, if that's the right platform when we think about margin for the duration of this year.
Yeah, I think we're making really good progress as we gain scale on these projects. We track what we call an O&M margin ratio, which is a similar measure to what you're talking about. We track it very closely and actually drive performance around that for the team. We do expect to continue to improve that from where we are today. I think when you look at it on a quarter-to-quarter basis, sometimes it can move around on you, but on an annual average basis, we are continuing to drive that ratio better, and we would expect as our scale gets larger. A lot of our costs, obviously, in these operating areas like the Northeast, are somewhat fixed, so as we drive volume and revenues against that, we are able to increase that. Similarly, in the West as well, we have that issue.
I would say the West is very mature in terms of its ability to drive costs down, that team, even without the benefit of big volume increases, that team has been continuing to drive our unit costs down in that area. I would expect us to continue to improve on that number, but you may not see it from quarter to quarter as much as you'll see it on an annual average basis.
Okay. My follow-up, just thinking about the Northeast G&P EBITDA ramp for the back half of this year. Recognizing the contribution of what Susquehanna and Bradford can lead to that. How do you think about the cadence or the rate of change with regard to gathered volumes and planned inlet gas volumes versus just how much incremental contribution from EBITDA there's going to be for Bradford and Susquehanna as they build?
I think, Susquehanna is going to be somewhat stair-stepped and be a little more driven. There is quite a bit of capability to boost volumes out there. As we saw this winter when we saw some good pricing hit locally in those demand areas, we saw some volumes pick up pretty rapidly. Part of that was because we had expanded the system on what we called our Genesis expansion out there. I think the thing that was impressive from my vantage point was the ability for the producers to respond when the pricing was there. We're going to see that occur as Atlantic Sunrise comes on, and we're certainly seeing all the activity in place today to keep up with that. Cabot has done a great job of managing the business and as well managing their markets.
They've got a couple of big gas-fired power projects that are coming on that they contracted to serve as well. Those projects are going very well. I think in the Northeast, we're going to see response to both Atlantic Sunrise and those gas-fired power generation facilities coming online. Down in the OVM area, we are just really impressed with the degree of activity going on on the rich gas there, the team's done a really nice job of winning new business there from business that was elsewhere. The team's really done a great job of continuing to grow volumes on that.
As Micheal mentioned, we're going to be up against our capacity limits there pretty quickly, we've got about another 150 million a day to fill up, then we'll have TXV-2 that we're in the process of constructing right now coming online, then TXV-3, which is another 200 million a day, would follow behind that. Don't really see much slowing down the Ohio Valley midstream area. That's going to be a little smoother, if you will, just because we're seeing adequate gas takeaway capacity out of the area right now. Now it's just a matter of the drilling continuing to fill up our processing. In the Northeast, I think we'll see a little more stepwise function that'll be late in the 2018 period for seeing those volumes come through.
Thanks, Alan. I appreciate it.
We'll take our next question from Eric Genco with Citi.
Good morning. Just wondering, can you remind me real quick, what is the test period again on the Transco rate case? When does that go through?
Yeah. Right now, we plan to file our rate case at the end of August, that test period goes through March 1st, assuming that we file there.
Okay. I wanted to ask.
March 1st, 2019.
March 1st, 2019. Okay. I realize this is kind of, again, a hypothetical. In thinking through sort of rating agencies and how some of this stuff goes, if you were to look through and you were to choose sort of a roll-up option, hypothetically, there's still a process from when that gets announced to when that closes, and it feels like Atlantic Sunrise is kind of around the corner at this point in terms of being online. We had heard at one point that the rating agencies were kind of eyeing Atlantic Sunrise and thinking about that in terms of sort of where you fall in the investment grade spectrum. Is that something where if you announce something and then eventually it closes, but Atlantic Sunrise kind of comes on in between, is that something you think you could get credit for?
What's the process for something like that like? I apologize for being theoretical.
This is John Chandler again. I think given the fact that the revenue stream is highly predictable because it's firm capacity, that when that project's in service, I do believe we'll be given credit, at least some level, pro forma full credit for Atlantic Sunrise.
Okay. Maybe I'll just ask one sort of philosophical question. I mean, a lot has been made about sort of the Northeast gas and associated gas from the Permian and sort of how that goes. I wanted to sort of ask philosophically, if you were to think through a scenario where you get through the next couple of years where LNG is kind of coming on and then there's a bit of a lull in sort of demand growth, how do you see the trade-offs between sort of a lower for longer price situation, which could obviously affect some of your customers. Being that you're levered to demand, low prices tend to spur demand. I'm just trying to think about how you think about looking beyond the next decade and what that holds for Williams philosophically.
Yeah. Great question. I would just tell you it's something we give a lot of thought to and study quite a bit. I actually think that the Permian supply is actually helping us in that there's much more confidence in low prices for longer, which is spurring big capital investment, continued big investment in capital. I think we're going to continue to see LNG expansion on the backs of that, where before I think there was some doubt about it. I don't think there's any doubt about the U.S.'s ability to produce low-cost gas supplies for a very long time. We are seeing tremendous amount of activity. We've got two methanol plants in Louisiana, big methanol plants that we're serving that we're building, have contracted now to serve, I should say.
We're seeing big capital go in trying to take advantage of low-cost gas, and I just think the Permian is just additive to that story, frankly. In terms of the Marcellus versus the Permian, even in the Bernstein report, which is probably the most negative towards the Marcellus as impacted by the Permian, even there you have a very large, like a 50% increase in volumes. I would say if that's the downside case for the Marcellus, that's pretty rosy from my perspective to get that kind of increase coming out of the Marcellus. Bottom line is, I think the Permian is really helping in terms of the big capital dollars that have to go in to sustain demand, and we're certainly seeing signs of that.
Thank you very much. Appreciate your time.
We'll take our next question from Craig Shere with Tuohy Brothers.
Good morning.
Morning, Craig.
The New York Northeast Supply Enhancement regulatory playbook sounds a little familiar when it comes to what you've been through with Constitution. Can you opine on, from a broader industry perspective, whether the promise of an improving regulatory environment for siting new projects is actually coming through or we're not really seeing any traction on the ground there?
Craig, this is Micheal Dunn. I would say there are challenging locations for us to permit projects, but it still doesn't negate the need for this project specifically. This is a very important project for New York and the Northeast. I'll just tell you, from what we saw over the winter in all of the Northeast, that two-week cold spell that was in New England between just after Christmas through the New Year's, they burned more fuel oil in those two weeks than they did in all of 2016, and had to import Russian LNG into Boston. I will tell you, that's somewhat ridiculous whenever you have the cheapest gas in the world just a few hundred miles away that can get to those markets. We think there's really a need up there.
The New York City Housing Authority this winter had some really difficult times keeping their buildings heated and with hot water service, just because of the failing equipment there on the boilers and the fuel oil systems. They really need to be upgraded, and they need to be upgraded with natural gas to reduce emissions and reduce costs for the citizens in those areas. It is a challenge to permit projects, there's no doubt about that. We're going to be out there and with our customers challenging those opportunities and making sure that we get a real definitive purpose and need out there into the public hands and get our projects permitted.
Yeah, I would just add to that, Craig. It certainly is the same Section 401 certificate, same one that got denied in the case of Constitution. It also got denied on Earth Day, that has a lot of similar ring to it. As Micheal points out, this one really is important for New York City, we really are starting to get some strong political support from folks that are actually locally affected by not having access to natural gas, we certainly think that that's going to be paid attention to. I probably don't need to remind a lot of folks on this call, Governor Cuomo is certainly trying to stay far to the left right now, we get that politically, we think the timing is an important factor here in terms of the approval and the state's actions on this project.
I think there's a lot of very strong positives for New York City in terms of dramatic reductions in their emissions by getting off of fuel oil. Almost all of this gas is going to take out fuel oil, there's actually a very large emissions benefit from this project, it's getting lower cost fuels into folks. We think ultimately the politics will turn to our favor on this, we've been working closely with the state, again, feel like there's very much an issue of timing regarding the denial on this that's more related to the governor's election, particularly in the primary. Does feel very familiar on one hand. On the other hand, we think we have some really strong politics that'll work for us eventually on this project.
Sounds good. Obviously logic doesn't work in some political situations, they hopefully will listen to constituents.
Yeah.
One other quick question. We've talked a lot about Transco and the March FERC order and tariff implications. Is the Northwest Pipeline rate settlement, because of the settlement, immune to that order, can it be dragged in in the next year or two?
Well, I think the FERC NOPR suggested that companies will be required to come in and explain how they're going to address the NOPR. Of course, we would address it that it was addressed specifically in our tariff, it does provide for the 35%-21% tax rate reduction. By the time we get to that point of actually doing that, we expect to also be able to say that Northwest Pipe is part of a corporate tax-paying entity, depending on whatever structure we put in place to make that happen. We do believe potentially that there would be some communication with the FERC, we don't think we have to follow the traditional process that others are going through since we have a settled rate case that specifically addressed this.
Right. Craig, our current rate that we're charging, as reflected this quarter, already has that 35%-21% step down. Even though we're actually receiving a higher cash rate, we're only recognizing the rate that would be appropriate to the 21%.
Great. I appreciate that clarification.
We'll take our next question from Shneur Gershuni with UBS.
Hi, good morning, everyone. Just a couple of quick questions. First, on the future of operations in the Northeast type of question. About four or five years ago, when NGL evacuation was an issue in the Northeast, producers tended to move rigs over to the bigger dry gas wells. This year, at some point, Mariner East 2 is expected to come into service. Are you hearing at all from any of your producer customers about an interest in shifting the rigs back to the more liquid-rich wells, which would also have lower gas outputs? Just kind of curious what you're hearing from producers.
I would say there is the move that goes back and forth that's dependent on a lot of things, and certainly right now, there is a lot of focus on the rich gas right now because propane prices have been high. Obviously, the spread between oil and gas is continuing to drive rigs towards the richer gas right now. I think we're seeing that's interesting as well, is somewhat coincidental, but the southwest part of the play, so West Virginia and Southwest Pennsylvania and Ohio, has the benefits of increased takeaway projects that have come online. They also-- You're starting to see a pretty big spread between TETCO M-2 and Dominion South, which serves that area, versus the Tennessee pricing and the Transco/Leidy Hub pricing, which serves the northeast part of the play.
Not only do you have right now better gas pricing in the southwest part of the play, you obviously have the benefit of strong rich gas. I would say there has been a leaning towards rigs being deployed in the southwest part of the play right now for those two reasons. As Atlantic Sunrise opens up and really starts to provide great access to real markets, not just sending gas into a cul-de-sac, but real new markets, we're going to see some increased activity in the northeast part of the play as well.
Two follow-ups to some of the answers you gave to previous questions. First, with Christine's questioning about the FERC, would you be able to confirm if your ADIT would be wiped out if you did a roll-up of WMB to WPZ as we've seen with some of the other ones that have happened?
We're continuing to look at that. I think the one thing that still leaves a little bit of a question mark in our mind is the fact that today, obviously WPZ is owned 74% by a corporate taxpayer. We are looking specifically at that to see what happens in that scenario. We're not clear at this point whether or not the material ownership by Williams of WPZ impacts that calculation at all. There's other scenarios that I think Christine was talking about. I'm not sure what the level of ownership was by a corporate-paying parent versus the public. I think the notion is that to a buy-in or a roll-up, there's a payment of all taxes due by the unitholders.
I think we're just processing through what that means relative to our specific scenario where 74% of the partnership's owned by a corporation.
Okay. One follow-up, I think you used the word corporate tax-paying entity in your response to Craig's question, and in some of the other responses, you have mentioned the word structures, which is plural. The obvious one to us is rolling up WPZ. Are there any other structures that you're looking at that you can share with us? Will you have picked the direction that you're going to take by the Analyst Day, or will that really come before you file the rate case?
I'll take that. There certainly are many other structures to look at, and you've heard the Street talk about those. I don't think we're going to get into a long description of all those various structures. There's multiple structures that are available in that regard. Primarily the difference and why there's so many available to us is what John pointed out, which is that at the Williams level, we're already a taxpayer at the Williams level, and therefore, there's a lot of structures available in that regard. That's the first part of the question. The second part of the question is, I'm not going to answer. We're not going to pin ourselves down as to when exactly we're going to answer this question at this point.
No, fair enough. I figured I had to try. Just one last follow-up. The argument about WMB owning 74% of WPZ's units and WMB being a corporate taxpayer. How does that argument differ from the fact that they're no longer allowing the ITA when it was originally constructed as the unit holders are ultimately taxpayers? I mean, the common manner or person out there does pay taxes. What's the distinction in the argument that WMB is a corporate taxpayer versus an individual paying personal income taxes as well also?
I think the distinction, specifically to the ADIT, and maybe we're twisting it a bit, but I think the distinction here is, if there were a roll-up transaction, there would not be a taxable event as it relates to WMB's ownership of WPZ. The notion that all taxes have been paid, including deferred taxes, I think is one that you'd have to analyze as it relates to the 74% ownership we have in WPZ. Does that make sense?
Yep. That makes perfect sense. All right. Thank you very much, guys. Appreciate the color.
Yeah. Thank you.
We'll take our next question from Becca Followill with U.S. Capital Advisors.
Good morning, guys. Just back to that same issue. There's been a lot of comments filed on the NOPR. A lot of them asked for the FERC to take into consideration before they made that final order, the comments on deferred income taxes in the NOI. Do you feel like you need to have a final order out of the FERC before you can elect a structure or decide what you're going to do in terms of a simplification?
No, I don't think we would want to wait around for that final order. Again, not saying exactly what the timing is, I don't think we would want to sit around and wait for that. I think the ability to completely turn that over is not real high.
Super. That's all I had. Thank you.
Yes.
That concludes today's question and answer session. Mr. Armstrong, I'd like to turn the conference back to you for any additional or closing remarks.
Okay. Well, great. Well, thank you all. I would just say a great quarter for us. Just continuing to be very predictable, I would suggest, and execution by our teams is tremendous. In the face of some pretty tough environment, the teams continue to execute very well. Really excited the way things are going on that front and really excited about our Analyst Day and rolling out a lot of exciting projects that are going to drive us into the long term as well. Thanks for your questions today and look forward to seeing you at Analyst Day.
This concludes today's call. Thank you for your participation. You may now disconnect.