Tallgrass Energy Partners' (TEP) CEO David Dehaemers on Q1 2014 Results - Earnings Call Transcript

May. 7.14 | About: Tallgrass Energy (TEP)

Tallgrass Energy Partners, LP (NYSE:TEP)

Q1 2014 Earnings Conference Call

May 07, 2014, 05:00 PM ET

Executives

Nate Lien - Investor Relations

David Dehaemers - President and Chief Executive Officer

Gary Brauchle - Executive Vice President, Chief Financial Officer and Treasurer

Analysts

Christine Cho - Barclays

Ethan Bellamy - Baird

John Edwards - Credit Suisse

Michael Blum - Wells Fargo

Selman Akyol - Stifel

Operator

Good afternoon. My name is Rachel, and I will be your conference operator today. At this time, I would like to welcome everyone to the Tallgrass Energy quarterly investor conference call. (Operator Instructions) I would now like to turn the call over to Nate Lien. Sir, you may begin your conference.

Nate Lien

Thank you, Rachel. Good afternoon, everyone. We appreciate you joining us, as we discuss among other things our results from the first quarter of 2014, which are released through our press release and 10-Q today.

Joining me on the call this afternoon are David Dehaemers, Tallgrass' President and Chief Executive Officer; Gary Brauchle, Tallgrass' Executive Vice President and Chief Financial Officer and Treasurer.

Before turning the call over to David, let me remind you that this event is being recorded and a replay will be available for a limited time on our website. I would also note that a slide deck will be presented as part of the call today and that deck will also be posted to our website following the call. Additionally, our comments today will include forward-looking statements and estimates. These forward-looking comments are subject to various risks and uncertainties and reflect management's views as of May 07, 2014.

Please refer to our filings with the SEC which are available on our website including our 10-K which provide a discussion of factors that may cause actual results to differ from management's projections, forecast, estimates and expectations. And please note that except to the extent required by law, Tallgrass undertakes no obligation to update any forward-looking statement.

With that, let me now turn the call over to David for his opening remarks.

David Dehaemers

Hello, everybody, and thank you for being a part of Tallgrass Energy Partners' first quarter 2014 earnings call here today. Just as a quick reminder, Tallgrass Energy Partners, TEP, acquired the Trailblazer pipeline from Tallgrass Development, we call that TDEV, on April 1, 2014.

Significance of that is these consolidated TEP results that you're seeing in our earnings release today for the first quarter 2014, do not include any other results of Trailblazer. Beginning with the second quarter, next quarter of 2014, Trailblazer will be a part of that. And so the distribution that we're making May 15 also doesn't include the Trailblazer distribution. We'll talk more about that as we proceed here.

Now, on to the results. You know, when I considered we increase our distribution for the third consecutive quarter that we completed our first dropdown with the acquisition of Trailblazer, and that TEP generated record distributable cash flow and distribution coverage for the first quarter, I have to say that TEP is off to a great start for 2014.

Net income for the first quarter of 2014 was $12.9 million and adjusted EBIDTA was $22.1 million. Distributable cash flow or DCF was $20.1 million after cash interest cost of $1.2 million and maintenance CapEx of $839,000. We'll be paying a cash distribution of $0.3250 per unit on May 14. That's an increase of 13% over our MQD when we went public.

Incidentally, we went public a year ago, one week from yesterday, so May 13 of last year, so we're coming up on our first year anniversary and it feel like we've had a very good first year.

Total distribution will be $13.7 million and that produces further first quarter coverage of 1.47. While we're on coverage I guess I have to tell you that last year we covered by over $10 million. When you get down to how much did we cover, an excess DCF coverage of over $10 million, and so far this year it's another $6.5 million. So when you put it all together so far over the year that we've been public, we've generated closed to $17 million in excess coverage.

Primary drivers of our strong DCF for the quarter were: good business performance across all of our segments. Our comparatively low O&M and maintenance CapEx spending for the quarter in relation to previous quarters. Lower cash interest cost for the quarters on the heels of selling the Pony Express assets to Tallgrass Development.

In the fourth quarter, you'll recall, just right at the end of the year, the conversion piece of natural gas pipe we sold from TEP into TDEV are the reason it was in there in the first place, as it was part of the TIGT assets, until we got the abandoned order. And hence we paid down our debt there at the end of the year. But that was also ahead of the debt finance Trailblazer again, which we closed on April 1.

With regard to O&M and maintenance capital for the quarter, not unlike last year spending in these quarters is less than Q1 as compared to Q2 and Q3. This is due to timing of planned downtime and routine maintenance as well for non-winter months. As you all know it's a lot easier to get work done on these things in the warmer summer months than it is in the cold winter months.

While we remain confident in our 2014 guidance that we gave you last quarter, there will be variability in our DCF and coverage quarter-to-quarter. I guess I would tell you here that we expect the second quarter to be our low point for the year. It's quite possible that we won't cover 1.0 for that quarter.

And so while I doubt the close to 1.5 coverage this quarter, we feel pretty certain it will be low and the second quarter coming up in the third quarter and even coming up more in the fourth. We still stand by our guidance that we gave you last quarter. However, when we think about TEP more broadly, then just be a 90-day day treadmill, we remain excited like I said about our delivering the rest of the year.

At this point, I'll turn the call over Gary. He'll give you some details on our Q1 results by segment. I'll come back to you to update you on the other assets like we've done in the past. And then we'll open up for questions-and-answers.

Gary Brauchle

Good afternoon, and thanks for joining us. With David having highlighted the pertinent consolidated figures, I'll talk for a few minutes about the balance sheet, and then provide you some detail on our segment performance in Q1.

As of quarter end, we had $135 million drawn on our $500 million revolver, reflecting the use of the approximate $83 million of cash proceeds from selling the Pony gas assets to TDEV. So keep in mind that we drew an additional $150 million on the revolver on April 1 to fund the acquisition of Trailblazer.

So when thinking about leverage in the near future, if you assume the $135 million at quarter end plus the $150 million drawn for Trailblazer and compare that to the midpoint of our 2014 adjusted EBITDA guidance of $89.5 million, debt-to-adjusted EBITDA is about 3.2 turns. And I can make a case that it's even a bit lower than that since our guidance only includes Trailblazer for three quarters in 2014. But either way, it's a healthy metric and nicely in line with our long-term goal of between 3 turns and 4 turns.

Moving on to our segment performance in Q1. The Gas Transportation and Storage segment or TIGT, as we all know it, produced adjusted EBITDA of $13.1 million in Q1, which was almost $1 million better than Q1 of 2013. Higher rates on firm contracted capacity and gas sales in a favorable pricing market contributed to the increase and adjusted EBITDA, when you compare the same quarter year-over-year.

While average firm contracted capacity of 636 MMcf a day was lower than the 667 MMcf a day for Q1 of 2013, the decrease was primarily due to the cancellation of TMID's lower rate transportation contract on TIGT of 100 MMcf a day, which we discussed and talked to you about in Q4 of 2013, our last quarter.

So while the firm contracted, volume figure was slightly down. The margin impact of that was muted by the West-end expansion we've previously told you about coming on line last quarter, and the rate on those volumes being higher than the ones they replaced for TMID's contract.

So we are pleased with TIGT's performance in Q1. But I would just remind you and reiterate what David said that O&M and maintenance CapEx are expected to be higher in the next two quarters at TIGT and for TEP in general.

Starting now with the Processing segment, TMID generated an adjusted EBITDA of $9.6 million for the quarter, which was up or increased approximately $2.8 million as compared to Q1 of 2013. The significant increase is primarily due to higher average inlet volumes as a result of our expanded capacity and higher commodity prices in our remaining spread-based contracts.

As we announced last quarter and talked to you about on the call at that time, one of our largest remaining spread-based contracts converted to a fee-based contract on February 1, which we're proud of, but the sharp increase in commodity prices, primarily propane in January, contributed into an increase in gross margin for Q1.

While average inlet volumes increased for Q1 of 2014 at 151 MMcf a day compared to 127 MMcf a day for the first quarter of 2013, and remained virtually flat as compared to Q4 of 2013, the last quarter. And this is reflective of weather and other customer delays, and ramping up to the expansion capacity that we expect to achieve later this year.

In Q1 of 2014, our Processing segment also began receiving distributions form a joint venture that we began providing water services to producers in the region, and we look forward to the continuation of those distributions and efficient operations going forward.

So in summary, for TMID, Q1 was a great quarter, but also expect to decline in Q2, as we take one of the plants down for maintenance and other work and we see O&M and maintenance CapEx increasing.

With the segment and the balance sheet overview complete, I'll turn it back over to David for some comments that I know you'll be interested in.

David Dehaemers

I know many of you are anxious to hear about our progress in Pony Express, the Pony Express pipeline and other recent positive developments at REX, and we intend to talk to you about that stuff. I'd like first to talk to you about Trailblazer, which is our newest addition here at TEP.

As we previewed with you on the fourth quarter call, in February, we closed the acquisition of Trailblazer on April 1 for a total transaction price of approximately $164 million. As Gary mentioned, the cash portion, $150 million of the acquisition was funded with a draw on our revolving credit facility, which helps make the transaction very accretive to TEP unitholders. The remaining $14 million of the purchase price was funded with common units that were issued to TDEV, Tallgrass Development, our private entity.

As we had previously said, we expect to recommend the TEP's board an increase in our annual distribution of at least $0.20 beginning with the second quarter of 2014. As you know that would probably be announced sometime in July and would be payable somewhere in the middle of August as is usual.

Further about Trailblazers. Trailblazer's rate case settlement has received certification from the presiding administrative law judge, and is now awaiting final approval from the FERC. However, the new rates have gone into effect and Trailblazer returned to a normalized EBITDA run rate for the first quarter of 2014. We're pleased with Trailblazer's Q1 2014 performance and would expect solid performance going forward. And again, first quarter Trailblazer 2014 isn't in these financials. It will be from April 1 going forward.

So now let's talk about the two remaining assets held by TDEV. That's the Pony Express Pipeline project and then the Rockies Express pipeline. Just as a reminder these assets are not currently owned by TEP and are assets retained by Tallgrass Development, TDEV, but clearly the commercial developments of these assets are important to the future growth of TEP as well, as you know we all look for, particularly for the Pony Express Pipeline to come on board this year and be placed into service and put into TEP going forward.

So with that, furthermore let me reiterate before I dive into each of those assets, that we continue to get a lot of questions about REX, which I understand on one hand, but REX is owned by our private entity TDEV and TEP is not a REX story at this time. We will entertain some questions about it, but the focus we're trying to make on this call is on TEP. We can see some point in the future where the REX story may merge into the TEP story, but for now we're just executing on our long-term game plan on that and we will talk about that a little bit here.

So talking about Pony. With respect to Pony and it's conversion to being a crude pipeline, Tallgrass Development has spent an excess of $725 million through March. This figure includes $11 million on the Northeast Colorado Lateral, we call that NECL as a reminder, and the $83 million purchase of the 430 mile section of abandoned gas pipeline that came from TIGT in the fourth quarter of 2013. So basically of the $725 million about $100 million has been spent on the legacy pipeline as well as our new expansion into Northeast Colorado.

We're progressing on schedule with the gas to oil conversion portion as well as the north and south spreads of the 260 miles new built. To-date all the new pipe has been laid, it's been welded, and its laying in the ditch and substantially all of it has been backfilled. So we continue to be very, very pleased with the progress being made on this. Our expectation is that we'll began hydrotesting here in the next few weeks and that we'll begin line-fill thereafter, maybe as early as sometime in June.

While progress is being made on the PXP mainline and we currently expect our project to be in service. In the third quarter, we've been advised to expect a slight delay in the completion of one of the upstream pipelines from PXP. As you know, we're going to pickup barrels in Guernsey, Wyoming and deliver them to Cushing.

We are picking up not only local barrels at Guernsey, but we are picking up barrels that come off of a upstream pipelines that are also in the process of being expanding and built, and so one of those pipelines is going to have a slight delay from the August, September timeframe that we are looking to startup.

So I guess the message there, this will likely cause a volumetric ramp up on the number of barrels being transported on PXP during the first several months of operations as opposed to kind of running full out on the first day it goes into service, again not totally unexpected. Notwithstanding that delay, a portion of those barrels coming on, we remain very positive and excited about the Pony project. Frankly, our plans are that it will be ready and be in service sometime in August.

Turning to REX. There are number of positive developments to report since our last conference call, as we continue to execute on our strategy to convert REX into a bidirectional header system. And let me repeat that for everybody, it is a bidirectional pipeline system, we are not reversing REX.

REX is going to deliver gas. It's going to be put in a lot of different points, points west, points east, and it's going to be delivered to a lot of different points, points east, west, and in the middle. So REX in particularly in Zone 3, which is the east end there from the Missouri border of Illinois to Clarington, is going to be a bidirectional pipeline.

Before we talk about the details of the other developments, let me first take the opportunity -- these guys keeping putting the stuff in front of me in writing and I get ahead of myself. So while it may seem a subtle difference in fact, I guess, the point of the bidirectional versus reversal is that gas is going to flow in REX to where it's nominated and it's going to come in on both the east end and west end.

Now onto the other developments. First, we're pleased to announced, we've increased the capacity on the Seneca lateral to 600,000 dekatherms a day and that it is fully contracted. We expect the first 250,000 dekatherms to be in service in June and the remaining capacity to come online in the fourth quarter of this year. As you can recall, we originally signed up somewhere between 200,000 and 250,000 dekatherms. So we have since signed new agreements to almost triple the size of that.

We've also signed binding precedent agreements for the remaining 1.2 million dekatherms a day, at least to west capacity within Zone 3, and are concluding a binding open season actually today. It's closing today for the capacity, which we expect to be in service by mid-2015.

Additionally, while it's too early to talk on the details on all this, we are exploring other opportunities that would add additional east-to-west capacity. We're very excited about these opportunities and continue to work hard, to again make REX a preeminent and critical piece of the country's energy infrastructure. And you guys can imagine the projects beyond what we're doing with the existing pipe or kind of traditional, add more compression, move more volumes through, as well as kind of looping and adding actual pipe to the system.

Let me conclude here by just saying, having come up on our one year anniversary, I'm very, very proud of everybody at Tallgrass. It's taken a complete team effort. We have close to 600 employees now. And I have to tell you in my view, our team here, which includes all of our employees has got to be one of the hardest working companies out there, if not the hardest and smartest working company. So very, very proud of all of them and I think we're doing well. We hope to continue to deliver outstanding results to everybody.

With that, operator, we will turn it over for Q&A session.

Question-and-Answer Session

Operator

(Operator Instructions) You do have a question from Christine Cho from Barclays.

Christine Cho - Barclays

You guys mentioned some one-time issues that impacted volume for TMID in the quarter. Would you be able to quantify how short you were versus expectations? And do you still feel good about the continued ramp up? Or I guess maybe something like 175 Mmcf today in the back half of this year?

Gary Brauchle

We did experience some weather and other customer delays not only in the fourth quarter, but in the first quarter. But we do expect to see volumes continue to ramp as we go throughout the year. It is too preliminary to tell you when we'll be running at capacity, but it is our expectation that ramp will pick up in Q2 and then move on throughout the year.

David Dehaemers

To put a little bit more color on that, as you get the weather that we had, that everybody had experienced this a little bit, the well freeze-offs and stuff, so the volumes are just not flowing into our plants, we were ready to process them. That's all past us now. We do have people that are continuing to fight some water problems in their wells, et cetera. But we're talking to those folks that are our customers daily and we expect within the next 60 days here that we're going to get closer and closer to that kind of 190 a day maximum volume that we hope to be at.

Christine Cho - Barclays

Can you tell us what you guys are running at to date volumes, just so we get a sense of what the shortfall was?

Gary Brauchle

Do you know what we were running at last month?

David Dehaemers

The quarter-end with volumes are about 150 or so. We are seeing those starting to pick a little bit in the month, but we're not talking anything hugely substantial at this point, I would say another 10 or 20, but we're continuing to watch that and will for the balance of the quarter.

Christine Cho - Barclays

And then can you just remind us what happened during fourth quarter of last year regarding this buyout of TMID transportation contract with TIGT?

Gary Brauchle

Christine, let me just take a quick stab at that. I mean, the TMID owns firm transportation capacity on TIGT. It was a contract for 100,000 a day and it was at a fairly little rate. That contract was terminated. And in the fourth quarter you might recall that there was a termination payment between TMID and TIGT.

And so what we did was disclose and explained that TIGT received the benefit of the $1.3 million in Q4 for that one-time termination payment. And it was an additional expense to TMID also in that same quarter. So net-net for the MLP of the TEP, there was no impact, but the segment results did reflect that payment and received in the fourth quarter.

David Dehaemers

Let me add too. We did that because we had 100s of days moving into a tenure too, and it was causing TMID to be market affiliate, didn't make any sense. It was a carryover from the predecessor owner, so we got rid of it. They're no longer market affiliates. They can talk to each other. The same amount of gas is going to flow, just flowing from other sources at other rate. So it was the right thing to do from a business perspective.

Christine Cho - Barclays

And you kind of touched upon this, but I guess if we can get more color, we have heard of other companies getting reverse inquiries from producers to build the brand new pipe. That sounds like it would parallel the third zone of REX more or less, which make sense given I think you've got kind of an overwhelming response from the open season that was well above the capacity. I am guessing you guys have kinds of max out what you can do with your existing pipe in the grounds. Does the parent have any interest or capability to root the lines that could potentially extend the backlog of assets to be dropped into TEP?

David Dehaemers

And that's what my comments were there at the end that we are looking at that. We are the ones with the pipe in the ground. We are ones with existing compression. Well, I know that others have maybe getting reverse inquires and other people have been talking about it, it only makes sense that the guy with the pipe in the ground, the guy with the existing compression would make the most logical sense to for additional piping compression in the ground and would have the most economies with that. So the answer is yes. I think I used the word looping. Those are things that we are working on now very hard, now that we've kind of conducted everything we can do with our existing pipe going bidirectional there in Zone 3. So we're working on that.

Christine Cho - Barclays

But it sounds like I mean to add more capacity, do you have loop the line? There is like nothing more you can do with compression and things like that.

David Dehaemers

No. Like I said earlier, we refer to that first and cheapest choice from a capital standpoint is adding compression. We can do that. We are looking into that. That will be more expensive. Obviously, the higher you run things up in terms of pounds per square inch, the more fuel it's going to take to do that. So while that's a cheaper capital solution, it's a more expensive operating solution. So we are investigating that, that's a cheaper capital version. The second would be both doing that in conjunction with looping, and yes, we're working on that stuff

Christine Cho - Barclays

And I guess it would be too premature to ask like what kind of capacity numbers you are looking at?

David Dehaemers

I mean, I would think, you could look at doubling the daily capacity of REX within the zone, for the area that we do it.

Gary Brauchle

Christine, let me double back on your team head comment to. I mean, I want you to also understand now that as my comments indicated earlier, we do see or we do have planned downtime in Q2 and Q3 and so the volumes that we talked about will be choppy across those quarters because of that downtime. But broadly speaking, as I mentioned between the beginning of Q2 and the end of Q4, we do expect on average to see those volumes ramp up on an inland basis.

Christine Cho - Barclays

Last question for me. When we kind of think about how this reconfiguration of REX work, at least for the east to west portion, is there just one rate to go anywhere in Zone 3 or are there different rates depending on where you get on and where get off?

David Dehaemers

There is no different rates depending on where you get on and get off. But the pipeline is not such that you can get off, and not everybody can get off at one place. So people are contracting right now for certain delivery points. So it's kind of an open season, that's out there, its public is for one rate, but it's for different delivery points. And again, we will gas coming in from the west and we'll have gas coming in from the east. And some of it's going to move to other points by the placement, displacement, some of it is going to move by compression, making the actual molecules move both ways.

Operator

Your next question comes from Ethan Bellamy from Baird.

Ethan Bellamy - Baird

So it looks like a volatile year for DCF coverage, where are you guys targeting long-term, if you look at '15 or '16, where do you want shakeout in terms of DCF coverage?

Gary Brauchle

Let me hit the first part of that for you, Ethan, just quickly and I'll let Dave do the second piece. Your comments around the volatile year, I would tell you that if you just look at the entire year, it remains in line with the guidance we provided. However, you are going to see that quarterly choppiness that we talked about today. And I would just kind of point you back to our calendar year 2013 quarter coverage and you saw some of that choppiness there. This is no different. It's a same phenomenon this year.

David Dehaemers

So I think your first point was just a statement of volatility. I mean, if were the Microsoft of pipelines, we could probably say, yes, we're going to be kind of in that same coverage quarter in, quarter out, give or take a point. So we're just not that way right now. In response to your question, what do we see kind of '15, '16, my crystal ball says '15, '16 were substantially larger in terms of EBITDA, et cetera with potential drops of Pony. I would say with that comes economies of scale, and I would say we would probably, long-term kind of look at the operating in that kind of 1.10 coverage area.

Ethan Bellamy - Baird

And then same question on leverage ratios?

David Dehaemers

We've told everybody all along that our goal is to get out of size and demonstrate that when we tell people we're going to do something, we execute on it. And that we from the start run our company, like a investment-grade company. And so we've been pretty clear, I think all along our long-term intention is to run the company with that kind of 3x to 4x debt to EBITDA ratio. Now that's going to be a little -- could be potentially choppy depending on what we do if we have an acquisition or we bring on a project that we're spending capital that is kind of a green or brownfield build, but that's kind of how we view it.

Ethan Bellamy - Baird

And one last question. Big picture, could I get you to opine on the recent natural gas price rally. How, if at all, has that changed your thinking or presented either opportunities or thoughts to your original game plan?

David Dehaemers

I don't think it's changed anything with regard to our game plan, I thought you were going to ask me to opine on why natural gas has come up and we aren't in the natural gas commodity business directly on the one hand, but I don't think it's fundamentally changed for us. I do think it allows a little bit of elasticity for a lot of people in that game of producers, et cetera. Obviously we're in the business of contracting with producer, shippers, as an example, to move hydrocarbons, whether it's crude or natural gas out of the production areas to other areas.

And so when you have $100 crude or you have -- and I know your question was more about natural gas that when you have $5 gas, the producers feel a lot better about producing net gas and getting it to markets, getting it to end-users and therefore they feel better about making longer-term commitments, et cetera. And obviously that aids our ability to do more creative things with our assets, such as REX, et cetera.

Ethan Bellamy - Baird

So is it safe to say that moderate tailwind on the volume metric outlook from the producing areas under footprint?

David Dehaemers

I think that's a good summary of kind of how we feel about, how I feel that about.

Operator

Your next question comes from John Edwards from Credit Suisse.

John Edwards - Credit Suisse

So just on follow-up a little bit here on REX. So when you're talking about it being bidirectional, and my understanding is the capacity on there is about 1.8 Bcf a day. So are you going to be able to be bidirectional for that full 1.8 Bcf, I guess first? And then secondly you're talking about potentially being able to double capacity. Would that be bidirectional or full double, part of it? And also I guess the complexity is in what zones? I mean I would assume it would skew toward the east side, but wondering if you could talk about some of those things out, that would really help.

David Dehaemers

Let me give you. Gas is fungible, right, so I mean it's that molecules are all the same and whether you're compressing it or not, molecules drip one way or another. You can clearly or probably not going to be bidirectional -- you're not going to bidirectional at the same time, so it's a fungible.

But lets' say for example, the pipe has two ends one in Wyoming, ones in Ohio. So if you had gas, and I'm just giving you an illustration to perhaps help you think about it, if you have 1.8 Bcf of gas going in Wyoming and it comes out of the pipeline in Missouri, then basically from Wyoming to Missouri, it's following from Missouri to Ohio is empty, right.

And so if you have gas coming in Ohio and it gets off in Illinois, then you have some molecules moving west to east, you have other molecules moving east to west. And again, I think everybody has the clarity of most of the new gas in the shale play is in the Utica and Marcellus. And it's safe to say that that's were our binding open season now in the east end is aimed. So most of what we're talking about is focusing on our Zone 3 here.

John Edwards - Credit Suisse

So would it be fair to say then that, I guess the way you look at this, the gas, it's sitting in this line, and then, in effect, you don't move it all, you effectively sort of swap it along the line with various parties and so they basically pay you fees to enable and to eject it at certain points and take it off at certain points?

David Dehaemers

Again, some of them are moved by displacement. All I can tell you is that shippers would put in the line where they put it in at, which most logically is in the west and east. And we will move it to wherever they have not moved to and where they have contractual rights to deliver it to. And so they don't really care how you necessarily get it there, whether you're running your compression or not, right. So if you have somebody put it in Ohio and wants to move it to Illinois, as long as they could move to Illinois they don't care and it's all fungible.

So there may be times when you're compressing and actually running your compressors to compress and move west to east or may be a time where you're running compressors in the east and compressing to run it to the west. There may be times when you're not running any compression, because you've got enough gas in the pipeline to deliver it to everybody who's nominated it.

John Edwards - Credit Suisse

And as far as potentially doubling capacity, about how much of the length of it do you envision?

David Dehaemers

It could as much, I mean -- we're investigating that now. I would say the next length would be in doubling Zone 3. We'd do the entire Zone 3, right now I kink of doubt it, that that would be the maximum. We would probably do it more to points that people are interested in getting too from, say, current and then the east for example.

John Edwards - Credit Suisse

I think I missed it. I think you were saying that there's going to be a bit of a delay on Pony Express, I missed. How long that would be?

David Dehaemers

I did not say that there was going to be a delay on Pony Express. We're still looking to place it in service in the third quarter, maybe the beginning of the fourth quarter. Our timeline actually is August. So it will be in service, we believe some time in August maybe September. Things do happen, though.

What I talked about the delay was we have a joint tariff with upstream pipelines that are going out of the Bakken to deliver down into Guernsey, Wyoming. They're not our pipelines. They are others that are part of our joint tariff. Those lines are being expanded and built by others right now. We've been kind of put on notice that they are running a little behind.

And so the delays are the other upstream pipelines. They are not major delays. We still think they will be in service by the end of year. It just may mean that instead of day 1, let's say, we're able to get in service September 1. Running day one, we won't necessarily be running 230,000 barrels day one, we maybe running 150,000 barrels.

John Edwards - Credit Suisse

So the pipes upstream from Pony Express are a little behind and that may delay the volumes coming on to Pony?

David Dehaemers

Yes. At least one of them is.

Operator

Your next question comes from Michael Blum from Wells Fargo.

Michael Blum - Wells Fargo

Just maybe stay on Pony Express, so two questions, really. One, is the cash flow or the EBITDA, however you want to think about it, is it purely driven by demand charges or is there a volume metric component? In other words, if the volumes ramp up to the upstream delay, does that mean cash flows ramp up from a lower base?

Gary Brauchle

It's kind of both, Michael. I mean there are volumes that are driven by demand payments. I'm not going to be able to peel this one and back entirely for you. But there are things associated with the upstream shippers on those pipelines that are demand payments, and so they have to get started.

There are other walk-up. So some of that will start, some of it will be delayed. There are also walk-up volumes that will show up a NOM a month prior and so those were kind of quasi. They are not demand payments, but we expect people to be ravenous to get in line for those. So they essentially have some of the characteristics of demand payments. But once the shippers start to ship on those upstream pipelines in particular, they do turn into demand payments.

David Dehaemers

Gary, I think where you headed was, do we expect cash flow ramp up as the volumes ramp up, and the answer is yes. However, I would tell you that we're talking, at this point, the notifications we've been given are months, not substantial delays like a year or anything like that. So we're talking a portion of the volumes delayed for a handful of month or so at this point.

Michael Blum - Wells Fargo

And then does that delay in that one pipe upstream, does that change anything in your thinking in terms of the timing of when you may drop the asset down or piece of the asset into the MLP?

Gary Brauchle

No.

Michael Blum - Wells Fargo

And then just on REX. The 1.2 Bcf, does that require investment by the partners?

Gary Brauchle

Yes. We have to invest somewhere around maybe invest in $100 million to make some compression bidirectional.

Operator

We do have a question from Selman Akyol from Stifel.

Selman Akyol - Stifel

Just two quick questions, if I may. First of all, can you talk a little bit more about your fresh water transportation JV, what we should be expecting out of that?

David Dehaemers

It's a small operation right now. We had an opportunity to invest in a pipeline that had already been negotiated with one of our natural gas producers in the Rockies that had already been working with these folks to provide a pipeline for water as well as the water to do some fracing in their area.

As we had an opportunity after this was already negotiated to invest in. And that is kind of what was the last few months turned into something where we may actually buyout therein at the end and combined them with us. It's very small, it's low double-digit investment in terms of millions of dollars.

We're very hopeful that might turn into something. The deals not done yet, we're getting close. The two principals that are part of it that would be working for us and with us, be with us, our former I think Bechtel and Halliburton folks. So they know what they're doing in this area. And we just think it might be an opportunity to do something different. I mean that's kind of as much as I can give you at this point.

Gary Brauchle

I would just tell you that, while it is modestly additive to the MLP and perhaps more so in 2014 then '15 and '16 as it relates to this particular investment. I would just kind of tell you that at this point, in those ranges, in those numbers, nothing that is overly substantial at this point.

Nate Lien

Operator, is there anymore people queued up?

Operator

(Operator Instructions) And your next question is from [ph] Patrick Baxley from [indiscernible].

Unidentified Analyst

I just had a quick question, and I'm sorry I missed this earlier. But the initial 200,000 Mcf that will be coming from east to west on REX, when is that scheduled to go into service?

David Dehaemers

It was June of this year.

Unidentified Analyst

And that looks like that's on track?

David Dehaemers

Yes.

Operator

And I am showing no further questions at this time.

David Dehaemers

So good luck, everybody. Thank you so much for joining our call. Appreciate your interest in Tallgrass. And hope you all have a good day and a good next quarter. Thanks.

Operator

And ladies and gentlemen, this concludes today's conference call. You may now disconnect

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