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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, everyone, and welcome to the Williams, 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, and thank you for your interest in Williams and 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 you momentarily. Joining us today is our Chief Operating Officer, Michael 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 and you should review it. Also included in our presentation materials are various non-GAAP measures that we've reconciled to generally accepted accounting principles and these reconciliation schedules appear at the back of today's presentation materials.
And so, with that, I'll turn it over to Alan Armstrong.
Great. Thank you, John, and 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 and 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 allow 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, and 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. And this is going to drive improvement in ROCE and shareholder value for many years to come. No one is as well positioned as Williams to capture the accelerating growth and demand for U.S. natural gas, and we look forward to updating investors about our significant achievements and the future plans at our Analyst Day event on May 17.
So, 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 and that we're delivering across all of our business segments. I'll drill down a little bit into the business segments. And then finally, I'll continue to outline the key topics that will provide a deeper dive into our Analyst Day event. But for now, let's move to slide 2 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. And now 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 and the absence of margins from the Geismar olefins facility, which was sold in 2000 – sorry in July of 2017 and that was about – that was the bulk of the $59 million increase in commodity margins that you can see posted in our number, so $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, that was up $53 million or 5% for the partnership's current business segments over the same period in 2017, and this was driven by a $58 million in increased revenues from our Transco expansion projects being placed into service in 2017 and 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 and I'll hit on that a little more in a minute. And all three of our current business segments showed year-over-year improvement in adjusted EBITDA. So, 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. And we did see higher expenses compared to 1Q of 2017, but 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 the quarter, and that was as we projected in last quarter's earnings call.
And we'll see that taper off – that impact continue to taper off as those wells depleted down through the third quarter of last year. The completion of Atlantic Sunrise worth about $105 million per quarter of incremental revenue for Transco will be a significant contributor to the growth we anticipate in later half of this year for the Atlantic-Gulf segment.
Now moving to the West, the West increased adjusted EBITDA by $17 million, and 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 9 of the 10 franchises versus first quarter of 2017. And the one area that was lower was the Barnett, which showed about a 5% annual decline from 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 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 and that's on an inlet – plant inlet gas basis, and we are seeing additional producer activity in liquids driven plays like the Wamsutter area and the Washakie Basin in Wyoming, the Eagle Ford, and now emerging is the Turner formation in the Powder River Basin, all 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% increase gathering volumes and increased gas processing business at our Ohio Valley Midstream complex in West Virginia, where we actually saw inlet gas processing volumes increased by 27% and NGL production was up 34% (00:08:40) 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 cost flat on a year-over-year basis and actually reduced operating expenses from the fourth quarter 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, and this was led by the Bradford County JVs that we increased our ownership in during the first quarter of last year.
We're seeing a significant ramp up in requests for system expansions as the Atlantic Sunrise and other key takeaway infrastructure serving in the Northeast begin to take shape. We expect significant growth in volumes and EBITDA from the segment by the fourth quarter of 2018. So, 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.
And 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% to 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 looking – turning to slide 3. We recapped some of our recent achievements here as we continue to build long-term predictable growth in the business. And as I've said earlier, we'll discuss our projects in greater detail at our May 17 Analyst Day event, but already this year, we've managed to set new delivery records on our Transco system. We also have started construction on the Gulf Connector, 475 million a day Gulf Coast LNG delivery expansion, so that's an expansion that goes from Louisiana into the – some of the large Texas LNG facilities, namely Freeport and Corpus Christi. And 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 9 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. And 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, and I will tell you that is thanks to some very dedicated and hardworking employees and some terrific planning by our team.
So, really have been very difficult conditions up there, but the team has continued to overcome that and 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.
Now moving on to slide 4, 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 17 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 and these give us great transparency towards predictable growth over the – not just in the short term, but very much in the long term.
So, we're really excited to see the way our pipeline for growth is continuing to fill in and we'll highlight that. We'll also address the recent FERC action on regulated pipelines held by MLPs, and finally many elements are coming together which provide great transparency to our 2019 growth, and we look forward to highlighting the key drivers of the significant ramp up that is now before us.
So, 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.
So, operator, let's take the first question, please.
Thank you. We'll take our first question from Jeremy Tonet with JPMorgan.
Good morning.
Morning, Jeremy.
Appreciate that you might want to wait for the Analyst Day on this, but I just wanted to touch base on the FERC and see if there's anything additional that you could share with regards the recent decision, and 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. And so, we don't expect any impact to our guidance. So, 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.
Got you. Thanks for that. And I think you touched on a bit on in your comments, but the West stepped down 4Q 2017 into 1Q 2018. 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, but anything else you can kind of share there?
(00:16:13).
Yeah, I would say that probably the biggest impact in the West was that Northwest Pipeline rate case, where we had a settlement with our customers and that did take the revenue down. So, I'd say that's probably our biggest impact in the West there. And on gathering volumes, keep in mind although sequentially we were down, we were very strong in Q1 2017 to Q1 2018. And I would just say on that we had very strong performance in Q4, primarily in the Haynesville, and 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.
And just in some of our gathering area, 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, but it really wasn't too bad this winter.
And 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, and in the West particularly that's where we've had a number of previously settled MVCs and other things where we received prepayments. And under the new revenue recognition standards, we're extending the amortization that over a longer period of time. So, there was 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 to $30 million between those period. So, there was a big step down related to non-cash revenue recognition items.
Great. That's really helpful. Thanks. And 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?
Yeah. This is Michael Dunn. I'll tell you in a couple of our areas would start in 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, 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. And 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. So, 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. But right now, they're anticipating 20 net Marcellus wells in Q2 and about 60 in the second half of 2018. And all of that volume comes on our Northeast Gathering system. So, 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 a continued growth in the Marcellus even despite what we hear around the Permian, so that's encouraging. Thank you for that color.
Sure.
We'll take our next question from Christine Cho with Barclays.
So, 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 transaction like that would have on your rate base calculation for your FERC assets.
Yeah. No, we don't think it would eliminate that now.
Okay.
Now 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 (00:20:53) the year-end relative to going from 35% to 21%. That would still be subject to possibly providing great relief back to the shippers, but 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 15 filing, we'll still be a corporate tax payer and we believe that that the deferred tax liability will still be out there and still be payable by the company. So, we don't feel like that has any rate implications. And at the same time, I don't believe we will be eliminated either.
What do you expect – well, if you, I guess, keep it in the – keep the pipeline in the MLP, what do you think – and you have to take it from a 21% to 0%, are you going to have to book more into the regulatory liability?
Yeah. I think that would be the outcome if that were the – if at the end of the day it was – it were in the MLP, you'd have an additional regulatory liability, yes.
Okay.
And 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. So, various regulated entities are responding to that NOI. So, I think it's still subject to that.
Okay.
But to the extent that the FERC follows kind of the same approach that is there on the 35% to 21% move, then yeah, you could expect that to happen.
Okay. And then earlier this year, it was out that Caiman was marketing their interest in Blue Racer. And you guys seem 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 out up to over 70%?
Yeah. Well, Christine, we don't get into the details of that, but we do have rights related to that type of transaction, particularly as it relates to the Caiman interest. And so, we're not to consider – nothing has really changed in that regard just because of our rights indicates the sale or transfer of interest there.
Okay. And then, 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 Michael 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 is 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. And so, in order for them to allow more time for their review, they did deny that permit, but we certainly have every right and every intention to re-file that permit, and the whole support of our customer National Grid.
Now, assuming we still get the Water Quality Certification and all data permits and FERC approvals in the same timeframe, it really wouldn't have any impact on the schedule. We do intend to re-file that in the next several weeks, and assuming that New York continues its review, which we think that it 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. So, 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.
Good morning. So, it looks like there was some solid growth on the volume front for the Northeast equity investments, but the proportional EBITDA lagged a bit. So, any color on the primary drivers there, whether it was maybe Blue Racer or Utica East or just what caused that variance of it?
Yeah. Most of the volume growth there was on the Bradford JV, but you are right, the Cardinal and UEO interest, they were declined on the rich gas, the Utica volumes there. And so, that had impact on that joint venture. So, primarily it was Bradford increases, offset by some Utica Rich decline.
Okay. So, just the lower-margin dry gas there so a bit of a makeshift?
That's exactly right.
All right. Okay. And I just wanted to follow up on Jeremy's question on the West.
No. But just to be clear there – Colton, sorry – just to be clear that we did see EBITDA increases on Bradford, but – so that – we had lower rates there, but you're right that Utica Rich we have higher margin on and that is where we saw a lower EBITDA.
Yeah. Appreciate that. And then, to follow-up on Jeremy's question on the West, if you could just give a little bit more detail there. I mean, I think you mentioned the weather impacts in the Eagle Ford, Haynesville, anyway to quantify that? I mean, 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 liquids-rich basins, whether that be Niobrara or your Powder River assets? So, 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. And I would just say the Haynesville ramp up was a very significant last year for us, if you recall us talking about that last quarter. And the rig activity there is still there. I think just we talked about other wells that they brought online just this week in the Haynesville, which is pretty significant lateral length there, so we would expect pretty significant production on an initial production rate from that well.
So, 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. But 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 planned turnaround at our Dilly (28:17) gas treating facility, sour gas treating facility there. And I think that was about a week of outage there. So, that was – that is an unusual event. It was planned, but it didn't impact the quarter. And I think on the Haynesville, as we've mentioned earlier, any time 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. So, 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. So, you always have kind of a little bit of a lull during the winter. And so, at the end of the fourth quarter, of course the first part of the first quarter and so, we'll see some of that pick back up. But 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 a last one. So, you hinted at some updates to the CapEx budget at the Analyst Day. So, I understand if you'd prefer to hold out most of the details. But 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. And it's kind of just 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 this 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. So, 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?
Yeah. I would just say we have plenty of structures to use and we don't intend to contemplate that path. So, there's plenty of other structures that we would employ, and so I do not expect us to follow rate case without the tax allowance in it.
Okay. That makes sense. And so then, if we do, and I'm 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 rating 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, but I would tell you this, I've had an opportunity to talk to 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 and I think it's consistent with what I felt it is, somewhere inside 4.75 times and ultimately down to 4.5 times. So, I think as a long-term view on a consolidated basis, we desire to be BBB flat, Baa2. But 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. And 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 and those are – the numbers I'm referring to are rating agency adjusted.
Okay. Perfect. Yeah. Understood. And then, last one from me just on Atlantic Sunrise, great to see the progress there. Sort of what's left – 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, but the contractors have done a great job progressing through the winter. And 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 of way. We've got four of the six horizontal directional drills completed. The other two, we should have pull-back here in the next two weeks on those and we are starting hydro tests. So, 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 for 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, so thinking about it on a percent 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 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. And 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 a really good progress as we gain scale on these projects. We're making good – we track what we call an O&M margin ratio, which is a similar measure to what you're talking about and we're tracking very closely and actually drive performance around that for the teams, and we do expect to continue to improve that from where we are today. I think if 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, and so as we drive volume and revenues against that we are able to increase that, and 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 and that team even without the benefit of big volume increases, that team has been continuing to drive our unit cost down in that area. So, I would expect us to continue to improve on that number, but you may not see it from quarter-to-quarter as much you will see it on an annual average basis.
Okay. And then my follow-up, just thinking about the Northeast G&P EBITDA ramp for the back half of this year, you know recognizing the contribution of what Susquehanna and Bradford can lead to that. How do you think about kind of the cadence sort of the rate of change with regard to gathered volumes in plant – in light gas volumes versus just how much incremental contribution from EBITDA there is going to be for Bradford and Susquehanna as they build?
Yeah. 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. But I think the thing that was impressive from my vantage point was the ability for the producer to respond when the pricing was there. So, 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've contracted to serve as well. So – and those projects are doing very well. So, I think in the Northeast, we're going to see response to both Atlantic Sunrise and those gas-fired power generation facilities coming online. And down in the OVM (00:38:04) area, we are just really impressed with the degree of activity going on, on the rich gas there and the team has done a really nice job of winning new business there from some – from business that were elsewhere. And so the team has really done a great job of continuing to grow volumes on that.
As Michael mentioned, we're going to be up against our capacity limits there pretty quickly, but we've got about another 150 million a day to fill up and then we'll have TXP-2 that were in the process of constructing right now coming online and then TXP-3, which is another 200 million a day would follow behind that. So, don't really see much slowing down the ORM – or sorry the Ohio Valley Midstream area, but 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. And now it's just a matter of the drilling continue to fill up our processing, but in the Northeast, I think we see a little more stepwise function that'll be late in the 2018 period for seeing those volumes come though.
Thanks, Alan. I appreciate it.
Thanks.
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 did that go through?
Yeah. Right now we plan to file our rate case at the end of August and that test period goes through March 1st, assuming that we file there.
Okay. And I wanted to ask – again...
(00:39:52)
March 1, 2019. Okay. And I realize this is kind of again hypothetical, but in thinking through sort of rating agencies and how some of the 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. So, we 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.
I think given the fact – this is John Chandler again. I think given the fact that the revenue stream is highly predictable, because it's firm capacity, when that project is in service, I do believe we'll be given credit, at least somewhat of a pro forma full credit for Atlantic Sunrise.
Okay. And then maybe I'll just ask one sort of kind of philosophical question and then a lot has been made about sort of the Northeast Gas and associated gas in the Permian and sort of how that goes, but 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 wall in sort of demand growth. How do you see the tradeoffs between sort of a lower for longer price situation, which could obviously affect some of your customers. But being that you're levered to demand, low prices tend to spur demand. So, 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 something we give a lot of thought to and study quite a bit. And I actually think that the Permian supply is actually helping us in that there is much more confidence in low prices for the longer, which is spurring big capital investment – continue big investment in capital. And so, I think we're going to continue to see LNG expansion on the backs of that, where in before I think people, there was some doubt about it. I don't think there is any doubt about the U.S.'s ability to produce a low-cost gas supplies for a very long period of time.
And so we are seeing tremendous amount of activity and we've got two methanol plants in Louisiana, big methanol plants that we're serving that are great – that we're building – have contracted now to serve I should say. So, 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 has impacted by the Permian, even there you have a very large, like a 50% increase in volumes, and so 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, and we certainly are starting to see signs of that. But bottom line is I think the Permian is really helping in terms of the big capital dollars that have to go into sustained demand and we're certainly seeing signs of that.
Thank you very much. I appreciate your time.
We'll take our next question from Craig Shere with Tuohy Brothers.
Good morning.
Good 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 citing new projects is actually coming through or we're not really seeing any traction on the ground there?
Craig, this is Michael 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. And I will just tell you from what we saw over the winter and all of the Northeast that two week cold spell that was in New England between just after Christmas through the New Year, they burned more fuel oil in those two weeks than they did in all of 2016 and had to import Russian LNG into Boston. And I will tell you that somewhat ridiculous whenever you have the cheapest gas in the world, just a few hundred miles away, they can get to those markets.
And so, we think there is 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 serviced just because of the failing equipment there on the boilers and the fuel oil systems. And 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. So, it is a challenge to permit projects. There's no doubt about that, but 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 certificate – the 401 certificate, the same one that got denied in the case of Constitution. It also got denied on Earth Day. And so, that has a lot of similar ring to it. As Michael points out, this one really is important for New York City, and we really are starting to get some strong political support from folks that are actually locally affected by not having access to natural gas. And we certainly think that that's going to be paid attention to. I'd probably no need to remind a lot of folks on this call, but Governor Cuomo is certainly trying to stay far to the left right now, and we get that politically, and we think the timing is an important factor here in terms of the approval and the State's actions on this project.
So, 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. And so, there's actually a very large emissions benefit from this project and it's getting lower cost fuels in to folks. So, we think ultimately, the politics will turn to our favor on this and we've been working closely with the State and 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 and particularly in the primary. So, the feeling does go 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, but 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 or 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 and it does provide for the 35% to 21% tax rate reduction. And by the time we get to that point of actually doing that, we expect 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. So, we do believe potentially that there would be some communication with the FERC, but 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.
And Craig, our current rate that we're charging as reflected this quarter already has that 35% to 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.
And 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 output? Just kind of curious what you're hearing from producers.
I would say there is a move that goes back and forth that's depending 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. And so, I think we're seeing – that's interesting you know as well and 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.
So 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 pricing, which serves the Northeast part of the play. And so, 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. So, 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. I would say 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.
Okay. And two follow-ups, just 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 (00:52:17) 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?
I mean, 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 has owned 74% by corporate tax payer. And so, I think in those other transactions – I mean we are looking specifically at that to see what happens in that scenario. And we're not clear at this point whether or not the material ownership by Williams of WPZ impacts that calculation at all. So, 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, and so, I think the notion is that to buy-in or roll-up, there is a payment of all taxes due by the unitholders, and I think we're just processing through what that means relative to our specific scenario where 74% of the partnerships owned by a corporation.
Okay. And one follow-up and 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, I mean 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, and will you pick 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, but there is multiple structures that are available in that regard. And primarily the difference and why they are so many available to us is what John pointed out, which is that at the Williams' level, we are already a tax payer at the Williams' level and therefore there's a lot of structures available in that regard. So, that's first part of the question. The second part of the question is, I'm not going to answer. So, 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 tax payer, I mean, how does that argument differ from the fact that they're no longer allowing the ITA when it was originally constructed as the unitholders are ultimately tax payers? I mean, the common man or person out there does pay taxes. How does – what's the distinction in the argument that WMB is a corporate tax payer versus an individual being paying personal income taxes as well also?
I think the distinction – I mean specifically to the aided 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. And so, the notion that all taxes have been paid including deferred taxes. I think it's one that you'd have to analyze and as it relates to the 74% ownership we have in WPZ. Does that make sense?
Yeah. That makes perfect sense. All right. Thank you very much, guys. I 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 and a lot of them asked for the FERC to take into consideration before they made that final order, the comments on deferred income taxes and 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. So again not saying exactly what the timing is, but I don't want to sit around and wait for that. I think the ability to completely turn that over is not real high. So...
Super. That's all I had. Thank you.
Thanks.
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. 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 IR teams is tremendous in phase of some pretty tough environment, the team's continue to execute very well. So 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. So, 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.