Generation Essentials Group

Thank you, Shannon. Good afternoon and thank you for joining the Tallgrass Energy quarterly earnings call.

As we discussed among other things, the TEP and TEGP results from the first quarter of 2017 which were released through our joint press release and 10-Qs this afternoon. Joining me on the call are David Dehaemers, President and Chief Executive Officer; Bill Moler, Executive Vice President and Chief Operating Officer; and Gary Brauchle, Executive Vice President and Chief Financial Officer.

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. 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 3, 2017. Please refer to our filings with the SEC, which are available on our website, including our 10-Ks and 10-Qs which provide discussions of factors that may cause actual results to differ from management’s projections, forecasts, estimates, and expectations.

Note, that except to the extent required by law, Tallgrass undertakes no obligation to update any forward-looking statements. Please also refer to our earnings release for reconciliations between the non-GAAP financial measures referenced in this presentation and the most comparable financial measure or measures calculated and presented in accordance with GAAP.

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

Good afternoon, everybody and thanks to everyone for joining our Tallgrass Energy first quarter earnings call. First quarter was another strong quarter for TEP with the acquisition of terminals and the operator of REX, the full in-service of the capacity enhancement project and continued strong operating results, all of which contributed to our 15th consecutive quarterly distribution increase and TEGP’s seventh consecutive quarterly distribution increase.

A number of positives have occurred since our last call in mid-February. We will provide additional details later in the call.

But in late February, we announced an agreement with Holly Frontier to connect their El Dorado refining complex to Pony Express. On April 3, we announced a very accretive acquisition of an additional interest in REX from TDev.

Effective March 31 and on April 12, Ultra Resources announced that it had completed its restructuring and emerged from bankruptcy. This means that TEP expects to receive its share of the expected approximately $150 million distribution from REX by mid-July and that would be half since we now own 50% of REX in TEP.

Before I dive into the summary of the financial performance, I would like to briefly touch on the economics of the recent REX acquisition, which we view as extremely favorable to TEP. As you know, TEP purchased its first 25% interest from Sempra in May 2016, little over a year ago, for approximately $440 million.

Around that same time, we amended and extended the Encana contract. Between that purchase and our next purchase of REX from TDev, which just happened, we have had the following occur.

First, we did not include any economics from Ultra in our calcs for our REX Sempra interest purchase; two, we did not know REX was getting $150 million from Ultra this July with 50% of it coming to TEP; and then finally, we also have now – even though we did not include anything from Ultra, we now have a new 2019 Ultra contract for $27 million annually that will last 7 years. You are all probably sitting there wondering why am I telling you this, because it helps setup my next comments on the most recent purchase of that 25% interest in REX that we completed here recently.

On March 31 of this year, TEP purchased another 25% interest of REX from Tallgrass development for cash consideration of $400 million. The current multiple on the enterprise value of the transaction based on our 2017 budget for REX, a budget that I would remind you is based almost entirely on contracted cash flows, would be just over 5x.

I think we all know how that 5x acquisition multiple compares to the multiples being paid for future cash flows of certain recent transactions such as those – I don’t know things being part – gathering systems bought in the Permian as an example. If you are to alternatively look at the multiple based on solely on current contracted cash flows post-2019 for REX, it would still be under 9.5x, assuming no additional and I repeat no additional, West End re-contracting or other new contracts on REX in the next 2.5 years, a very unlikely scenario on our opinion.

I would say it’s not only unlikely. It’s not going to happen.

The punch line is, any way you analyze it this is an extremely favorable acquisition for TEP as we have demonstrated since TEP’s inception nearly 4 years ago. TDev, our private entity, has been a very supportive sponsor and will continue to be a supportive sponsor going forward.

Now, let’s review the first quarter financial results driving our distribution increases. Adjusted EBITDA for TEP was $115.1 million, again inclusive of 3 months of distributions of our initial 25% interest in REX.

But none of the 25% interest in REX that we closed on March 31 or April 1 whatever the case maybe. If you were to include the quarter’s net deficiency payments, primarily from Pony Express, in adjusted EBITDA – and we have been over that with everybody, the reason that they are not in there is because it’s deferred revenue, but it is in cash flow.

So, if you were to include the quarter’s net deficiency payments primarily from Pony Express in adjusted EBITDA the amount would have been $131.2 million or an increase of $5.3 million from last quarter. TEP’s DCF for the first quarter – now we are on DCF, was $117.6 million, an increase of $7.9 million from Q4.

And Q1 coverage was a very strong 1.29x with approximately $26.2 million of cash generated in excess of distributions. Since TEP’s IPO in May of 2013, our cumulative excess coverage is $158.6 million and our cumulative coverage ratio is a very healthy 1.22x.

This quarter’s strong financial metrics supported TEP’s increasing its quarterly distribution by $0.02 per unit to $0.835 or $3.34 annualized. This represents a 2.5% increase from the fourth quarter of 2016 and an 18.4% increase year-over-year growth Q1 last year versus Q1 this year and approximately 190% growth from our annualized minimum quarterly distribution of $1.15 essentially our growth from our IPO nearly 4 years ago in May 2013.

As a result of the $0.835 distribution at TEP, Tallgrass Equity will receive distributions of $47.6 million on its $20 million TEP common units, its GP interest and its IDRs. Based on that amount, a distribution of $0.2875 or $1.15 on an annualized basis will be paid to Class A shareholders and to holders of our Class B shares.

This represents an increase of 3.6% from the fourth quarter, in other words sequentially and 36.9% year-over-year growth and approximately 116% from the annualized quarterly distribution of $0.532 at our May 2015 IPO. I will now turn the call over to Gary who will provide additional financial details, Bill will come in with some of our operational stuff, and then I will wrap up with some miscellaneous comments at the end.

So, Gary?

Good afternoon, everyone. Starting with our segment performance at the Crude Oil Transportation & Logistics segment which now includes Tallgrass Terminals.

That segment generated distributable cash flow to TEP of $71.1 million for its 98% ownership interest in Pony and 100% ownership interest in Tallgrass Terminals during Q1 of ‘17. This represents a slight decrease as compared to the $75.6 million for Q4 of ‘16, which is primarily attributable to lower incremental barrel shipments during Q1.

For Q1, average daily throughput at Pony Express was approximately 262,000 barrels a day as compared to Q4’s average of approximately 288,000 barrels a day. As we have mentioned in the past, we are not overly focused on daily, monthly or quarterly volumes at Pony Express.

Pony Express is contracted at just under 300,000 barrels per day. It’s important to remember that the receipt of payments on those firm take or pay commitments not throughput is what drives current DCF at Pony Express.

I would also remind you that Dave said last quarter and he expects Pony Express throughput volumes to average plus or minus 5% to 10% of the contracted volumes over a longer term period such as a year, but not necessarily during any given 90 days. Simply put, volumes will not be perfectly linear.

For example, in January of this year, Pony Express averaged approximately 242,000 barrels a day. We view this not as a trend, but rather as anomaly caused by a convergence of factors such as weather for example freeze offs, new drilled, but uncompleted wells not having come online at that point in time and a couple of other customer or producer behaviors that were temporary.

As a way of further illustration in March of 2017, Pony averaged approximately 277,000 barrels a day. As we have stated consistently, we continue to increase supply and demand connections on the system to best position Pony Express for long-term sustainable cash flows and growth of those cash flows and to minimize throughput variability.

Our interconnect with Holly Frontier is yet another example of executing on that tried and improve strategy. Next, we will turn to natural gas transportation and logistics segment, which includes TIGT, Trailblazer and the operator of REX.

Also included is our initial 25% interest in REX for Q1 and increasing to approximately 50% going forward. The segment produced adjusted EBITDA of $53 million, up approximately $8.5 million as compared to Q4 of ‘16 and up approximately $35.8 million as compared to Q1 of ‘16.

The increase from Q4 is primarily related to increased distributions from REX that were a result of the full end service of the capacity enhancement project as well as our January 1 acquisition of the operator of REX. We have again included in our press release summary financial data on REX as a whole and when you compare REX’s Q1 ‘17 with the prior year same quarter, the decrease is primarily attributable to the amended and extended Encana contract which we detailed for you previously.

And just as a reminder, that new contract went into effect in May of 2016. Firm contracted volumes for TIGT and Trailblazer averaged 1.6 billion cubic feet a day during the first quarter, which was consistent with the prior quarter.

Since REX’s capacity enhancement project has come online at the beginning of this year REX’s Zone 3 has continued to flow at or near the currently available 2.6 billion cubic feet a day capacity on that segment of the pipeline. The processing and logistics segment generated adjusted EBITDA of 6.1 million for Q1 representing an increase of 1.1 million as compared to Q4 of ‘16 and an increase of 2.7 million as compared to Q1 of ‘16.

Processing volumes were consistent with those that we have seen for a number of quarters now and right around 100 million cubic feet a day. The adjusted EBITDA increase over the prior quarter is mainly due to the contractually ramping take or pay volumes in our water business that we have mentioned now on a number of previous calls.

Focusing for a minute now on our capital structure at TEP. At the end of the first quarter, TEP had approximately 180 million of liquidity available on its revolver and TEP’s leverage as of quarter end March 31, was approximately 3.4 times again after funding the REX acquisition in cash of $400 million based on the trailing 12 months adjusted EBITDA is calculated according to our credit agreement.

So leverage at the end of the quarter was 3.4x debt to EBITDA. Our credit agreement matures in May of next year and accordingly, we will be working with our very supportive bank group in the near-term to address that maturity.

And as for the drawn balance on the revolver, since most of our significant known capital needs are behind us for the calendar year, we will consider long-term debt financing transactions perhaps only when the markets are favorable. And with that let me turn it over to Bill now for a discussion of recent developments at each of our assets.

Thank you, Gary. Good afternoon.

As David mentioned in the opening, it was another strong quarter of operating performance for our assets. REX is a first asset I will update you on.

And as a reminder, Tallgrass development has just over a 25% ownership interest in REX and TEP now owns approximately 50% of REX. As we mentioned on our Q4 call and as some of you have seen through REX’s bulletin board, we launched a non-binding open season for up to an additional 150 million cubic feet a day of potential space on REX from East to West and Zone 3 as a part of the capacity enhancement project.

We are still in the process of evaluating the operational availability of the capacity based on receipt and delivery pairs and pathways and we will provide additional details as we finalize any commercial agreements. As Gary mentioned earlier in the call, REX has been flowing at or near its 2.6 billion cubic feet a day of capacity since the full end service of the capacity enhancement project in early January.

In addition to Zone 3 running full, recently we have experienced very strong flows on the West end of REX. From March 11 to April 26, REX averaged nearly 1.7 billion cubic feet a day of West to East throughput with total throughput on the pipeline on peak days reaching as high as 4.5 billion to 4.6 billion cubic feet per day, which is a record for REX.

While some might say it is too short of period of time to call it a market shift, it is positive nonetheless and we are encouraged by the increased volumes and utilization of the West to East flow path. This should translate positively for our re-contracting effects and our expected Zone 1 and Zone 2 enhancement efforts over the next couple of years.

In addition, our commercial team continues to focus on connecting incremental demand to REX, while we aren’t in a position to provide any specific details at this time, we have been making good progress and are seeing a number of new industrial and local distribution opportunities which will add demand load to REX. Moving to Pony Express, as you may recall last quarter, I mentioned that our commercial team was very close to signing an agreement to connect additional demand to Pony and we are pleased that it happened at the end of February.

As we have reported, the design capacity of the Holly Frontier connection will be well in excess of 100,000 barrels per day and we expect it to be in service by the fourth quarter of 2017. This is another important milestone and a concrete example of our efforts to further diversify the supply and demand on Pony Express.

While we are not able to provide specific details at this time, our Pony Express commercial team is actively working on a number of additional opportunities. Details will come as those are commercialized.

Our TIGT and Trailblazer pipelines continue to perform well and remain two of our valuable assets that are well contracted and experienced excellent customer retention. This year alone, TIGT has already extended term or increase volumes or both with a number of our customers.

In addition, we are in discussion with three customers that could add additional volumes on the system and are evaluating a couple of other creative opportunities that could prove beneficial to TIGT and its customers. At Trailblazer much of the same activity is happening, but on a smaller scale as you might expect.

I shared these opportunities with you not intending to indicate that these are transformative financial events for TEP, but to show you that we remain very focused on all of our assets regardless of size, but most importantly we are focused on how we can maintain or enhance end market services that each can offer. At TMID and BNN, the water business, we have continued to see some notable up-ticks in activity.

The volumes in our TMID business for the first quarter were up slightly from the same period in the prior year and we continue to see ramp up in the BNN water business both on our existing assets and with new opportunities that we have recently executed. Not surprisingly in this commodity environment and with the years of today’s production technology fresh water and plough back needs are at an all-time high and projected to further increase and our BNN team is seeing the same all time high opportunity environment.

We have recently closed on one small acquisition that enhances our footprint and are actively working on a number of others in a variety of basins. Finally, let’s turn to Tallgrass Terminals.

As we have mentioned on past calls, our team continues to move forward on the South Cushing and Guernsey terminal projects in addition to other opportunities, one of which is in advanced stages. In short, we continue to have high expectations for growth in our terminals business and we hope to be able to share details on several of these in the near future.

With that, I will turn it back to David for his closing remarks.

So before we wrap up the call, I am going to just talk about a couple of things here. And this is always the fun part for me, because I don’t know if I can blame it on the lawyers, but they always let me hang it out a little more here.

So what I would like to do first is point out to you that you don’t see Tallgrass in the headlines making high-priced acquisitions in the current hottest basin. Instead, you count on us to stay focused on the execution of our business plan, looking for accretive organic M&A opportunity, managing our business for long-term returns and not necessarily for the next 90-day reporting cycle.

I think we can all agree that we have done a pretty good job of this over the last 4 years at TEP. TEP, in fact, has grown from an S-1 forecast of approximately $76 million in EBITDA to $650 million at the midpoint of our 2017 guidance, with distribution growth of 190% through Q1 of 2017 since our IPO.

Our plan is to continue to that execution and performance in the years to come. So I am going to leave you with these two items.

First, we – the Tallgrass team will be disappointed if in the next 90 to 180 days we are not able to share with you at least a couple $100 million of acquisitions and brownfield build-outs. We don’t say this whimsically or lightly.

We have identified 42 projects, totaling over $6.1 billion of known potential acquisitions/builds for TEP. And I would tell you, not – most of that is frankly not acquisitions, but builds.

Once you risk-weight these projects, two of which are in excess of $2.5 billion each – so that would be two projects obviously making up $3 billion of that and we assign a very low probability to those two since the planets, stars, commodity prices would all have to align for those two large projects, which they could. They are not a stretch.

We believe in the next 2 to 3 years approximately $1.5 billion of those identified things is reasonably achievable and within our control to some extent. Obviously, even though these are known with even some, to a certain extent, within our control, they always need to be executed on.

Made to happen, closed and done so profitably. We intend to give all that our maximum effort.

The second and final thing I would leave you with is we announced when we did the REX transaction that for the second and third quarter we would be increasing our – recommend increasing our distribution to the board by, I think we said at least $0.10, sorry, over the next two quarters and that would be basically payable on August 15 for Q2 ending June 30 and then November 15 Q3 ending 9/30. I am not sure everybody kind of gets the significance of that.

So what I am going to do is give you just a little what-if scenario. So, if I ran a number of these, but I will just give you – if we were to increase the TEP distribution by $0.08 in the next quarter that would be a sequential growth rate from – of TEP of $0.096.

That would be an annual raise of $0.32 and again quarter-over-quarter, a 9.6% increase. At TEGP – therefore, then you say well what are the effects on TEGP of that?

At TEGP – and that would result in a $0.0585, call it almost $0.06 increase at TEGP, or a sequential quarter-over-quarter growth rate of 20.3% in one quarter alone. In addition to that, if you do that math, close to $0.06, $0.585, you get $0.24 annual increase at TEGP.

And then we also then have flagged the remaining amount available for Q3. And frankly, we don’t stop there.

Our plan has increases every quarter built-in. Don’t think the market quite realizes that and those are some pretty high popping numbers that we are already kind of telling you we believe will happen unless something really freaky happens.

So with that, operator, I would – before we go to the Q&A, I just want to again thank all of our partners and shareholders for their confidence in investing with us. If you are partners of ours, we appreciate it.

We would like you to be bigger partners of ours. If you aren’t partners of ours, we would like you to think hard about investing side-by-side with us.

If you think – if you are thinking about selling your interest in our company, while that’s your prerogative, it is my personal goal to do everything I can to make you regret that decision. Having said that, operator, we are going to turn it over to you to handle the Q&A.

Good evening, guys.

Hey, Krisitina.

Bill, I know payments and you guys outlined this at the beginning, are based on contracted levels versus throughputs. And you know you did a good job saying that nominations vary a lot month-to-month, but maybe can you just touch on also where we ended April?

And I know others have mentioned like freeze-off and DUC issues, but you guys also mentioned something on temporary producer behavior I think you alluded to. So any color there would also be great?

Yes. We have kind of decided we – I mean I appreciate your question.

I understand why people would want to know it, but again, it really isn’t in keeping with what we said, which is its a little bit like one of my favorite books. You give a mouse a cookie then they want a glass of milk, they want a glass – you give them a glass of milk and – so we are not going to talk into the current quarter as to volumes, etcetera.

Again, I think you should be more than satisfied with our position that we are going to be 5% to 10% of volumes for the year 2017. I believe with my whole heart and soul by the end of the year, we will look back in that 12 months, we will either move 5% or 10% less than 298,000 barrels a day or we are going to move 5% or 10% above it.

So, we decided we are not giving out month-to-month stuff like that. However, giving – having said that, I guess what I would tell you is that we have had days that have been 350,000 barrels a day, 360,000 barrels a day and then we have had days where it has been 230,000 barrels a day and it’s just not worth to brain damage to spend any more time on it than that, frankly.

I think with regard to certain customer behaviors, we could have a long debate about Grand Mesa and Saddlehorn and White Cliffs and DAPL. The fact of the matter is, those guys have come and/or are coming into service.

I think some of the things like them needing line pack for those lines. If you think about – let’s just say XYZ pipeline is 500,000 barrels a day and it takes 10 days to move it.

Those guys need to line pack that thing with 5 million barrels of oil. Well, that just isn’t sitting around everywhere.

And so you have customer behaviors that aren’t going to be normal where you have people willing to buy and pay up for barrels of oil that would normally come through certain pipelines to get ready for line pack in other pipelines etcetera. Those are anomalies and things that don’t continue.

Got it. And shifting gears maybe a little bit, you guys – David you have done most of what I thought you were going to do for the whole year execution wise and we just finished up April.

So meaning like drop-downs and you mentioned some of the stuff on the interconnects as well. So how do you think about strategy or kind of what you are focused on for the next 12 to 18 months?

What should I be thinking about there?

Would you mind repeating the first part of what you have said, I kind of reengaged half way in the middle relative to...

You have done most of what I thought you were going to do for the year and we are already only in April, so nice job on executing on all of that. How do I think about the next 12 to 18 months?

So I will say some first and I think Bill probably wants to chip in. I think the way you think about it is exactly in my comments.

So I think we will be – I am not going to tell you what they are. But I think in the next quarter or two quarters, 90 days to 100 days, if we don’t have a couple of $100 million worth of acquisitions last projects that we are going to execute on to tell you about we will be very disappointed.

So I guess the way I would answer that is I would encourage you to – so far I think we have done everything we said we are going to do. I guess I would encourage you to think about that I am going to give these guys the benefit down if they are willing to make a statement like that that’s what’s going to happen.

It sounds perfect. So, I will wait next quarter eagerly?

Yes. And I think in addition to that we talked about a number of opportunities that are on Pony now to increase the supply and demand diversity.

Those are a long way along their commercialization timeline. We have talked about Cushing and South Cushing Terminal activity which is also along its commercialization timeline.

REX continues to add industrial and local distribution load adding demand to it. Our BNN Water group has had a number of small acquisitions that for disposal facilities and a number of different basins that are going to continue to grow and be able to provide producer services.

Yes, the point David is trying to make is, we have told you guys all along, we are not just a drop down story, we have a very large backlog of opportunities that our commercial teams aggressively pursue on a daily basis and those things are coming to bear. And it’s all the hard effort that those teams have put forth that we expect in the next 90 days to 100 days to be able to let you know exactly what some of those are.

So we are hard after it.

Perfect. Excited about what’s to come.

Thanks guys.

Thank you.

Hey, Ethan.

Hello, gentlemen. So, a couple of questions for you, first when would – when should we expect the timing of the last REX dropdown?

Yes. And when you say we, I guess you mean everybody, all the entire world, the public.

Well, I meant the real we, but we can go with your guys.

When anybody asks around here, you say we, when should we do something, I was asking who is we, so anyway. I think it’s going to be next year and I would say probably somewhere in that kind of second quarter kind of the same thing April 1 to June 30 timeframe.

Okay. And you did the last drop without any equity alongside, is your position still that you are – the balance sheet is okay and you are just going to be opportunistic on potential unit issuance?

I mean our balance sheet is great. I mean we can – the things that we have that, I am thinking about here that I think we could announce again in the next I said 90 days to 100 days.

Bill made a mistake when he said 90 days to 100 days. But I think that – I am kidding, you did say 90 days to 100 days, but anyway.

We are in fine shape. I mean we have – so we don’t have to do anything, it’s going to be completely opportunistic.

Again keep in mind that this isn’t our first roadie, we have been doing this for a while. And so as we have something that’s bigger that has more capital requirements coming, we would like to think that we are now in a position to be ahead of the market rather than behind it.

Got it. And can you update us on the timing and the potential economic impact of the Holly connection?

Bill?

I think we said in our prepared remarks that it would be fourth quarter of ‘17. It’s just a matter of time to get the pipe and the measurement facilities in.

And we also mentioned that it is designed for up to 100,000 barrels a day. We suspect Holly will start small like Ponca did getting a taste for the crude, but once they run it through their process, I think they will find it to be highly efficient crude to crack.

And we would suspect those volumes would go up rapidly thereafter.

I think relative to economic impact Ethan, I mean I think about it this way you know for better words, I am kind of Royals fan and I am learning very hard the last ten games that a game is nine innings long and they have been very long here these last 10 games. And a season is 162 games long, so right.

So when we do things like hooking up Holly and a couple more things we are working on that we hope to announce soon, it isn’t necessarily to say wow, look, that’s another $5 million EBITDA in six months from now, okay. You guys all know, we have said it over and over and over again Pony is capable of doing a lot more.

And when everything is right, our goal is long ball and long ball for us is to give customers in the Bakken, the DJ, the Powder and Kansas many, many different places to have their crude go. And that’s where the value will be.

So it’s impossible to say that, well by spending $10 million on this Holly interconnect, all we know is that we are pretty sure Holly is going to take volumes and we are pretty sure that’s going to be very valuable to some of our upstream producer shipper customers in the long run.

Right. And then in regards to that 42 project backlog, could you give us maybe some granularity on that, is that all contiguous, is any of that Greenfield and new basins or is that sort of budding existing assets?

I was thinking about it until you kind of colored it up yourself, I was thinking about saying no, 42 is more than I have ever given you before. I guess what I can’t tell you is well there are some assets that aren’t necessarily perfect to our system.

I think there are acquisitions that are partnered to our system. There are Brownfield build outs that are in that number etcetera.

And so there are very, very specifically identified, but I am not going to give you any more than what you asked for. There is very little - the two bigger projects that I talked about I suppose one would be a Greenfield the other one would be a Brownfield.

But again those are so lightly discounted, they don’t make a right now in our thinking in terms of the $1.5 billion I gave you in the projects, you take two out, you are left with 40. And so that’s about as much as I feel competitively that I can you give at this point.

Alright. Thank you very much, David.

I appreciate it.

You bet.

Hi, Gabe.

Good afternoon guys. I just had a quick question sort of on the comments on zones one and two in seeing good flows there, I guess Dave I think in the past you have also talked about potentially those molecules going all the way west to California, but I am also just curious in terms of the recent high flows you have seen, I think California markets are pretty saturated due to high hydro just trying to gauge, I think you made a comment helping the in terms renegotiations there, do you think some of those flows are sticker, do you think some of those flows may be disputed due to high conditions in California and molecules now one in U.S.

maybe?

Well, I think Bill is going to give you more, Bill or Matt are going to give you more fulsome answer about the recent activity and what’s going on with that. Longer term, we are going to re-plumb zones one and two and we are going to make our piece, which would go back to let’s call it the Wyoming, Utah border available to go back that far, to go the West Coast isn’t just California right, I mean it’s Oregon, it’s Washington State, etcetera.

So that’s number one. So all that is going to happen, none of that though has to do with what we have recently experienced, which is a long period of time where, I mean when guys add up 1.8 which is what REX was originally built at and yet up the 2.6, which is now the bi-directional in the Zone 3 as well as the power up, that adds up to 4.4.

I hope you guys were listening very carefully, because Bill said, that we have actually experienced 4.5 and 4.6 on a couple of days. Okay, so do you make – can you help with the reason.

Yes. I think of note is, we have seen Western volumes approach 1.8 or 1.4, but it usually is 4.1 or 4.2 of the coldest days during the winter, a polar vortices comes into the Midwest and everybody is capturing expanded basis because of that.

This lasted for 45 days. I don’t know if it’s a picture of the market to come, but what we do know is that the Permian is picking up in gas production and the Permian has easier access to the West Coast than perhaps Rockies volume does.

And you have Canadian volumes growing, you have Bakken volumes growing. We are running out of places for that gas to go.

And I think people are quickly realizing even though they hold FT today at an escalated rate that they signed up for some 8 years ago, I think they are finding out that that’s the flow path where they can get their gas to market period. And we think that’s going to likely continue and bodes well for west to east flows.

Now, the bi-directionality just provides optionality for our markets and marketers love volatility and optionality. And I think we are going to make the system available to provide them both.

And Matt, do you have any additional?

I would bifurcate it pretty carefully on the East Coast between Northern California and Southern California. And obviously Southern California is more easily accessible with some of the Permian gas that people are focused on.

I think Northern California has little bit of its own dynamics at times. But as we talk about going West there is a lot of markets that are west of Wamsutter with Nevada and Oregon and Washington state.

And so the dynamics there it’s not – when we say go west it’s really go west of REX, there is a lot of different places for that gas to go and markets for that gas to reach.

And then the final thing I would tell you Gabe is maybe a little bit more than you want to know too, I mean, I do think there is probably a little bit of Mid Con storage – refill storage going on that’s unique – maybe not unique, but it’s just slightly different than in the past. And then I think also you do have a lot of power generation coming on that isn’t necessarily co-located on REX, but it’s located off of all these interconnects that we have.

And so I just – you can’t dismiss or underweight any of those things.

Yes. Right now, we have 0.8 BCF of interconnects, with almost 400 million a day of power plants that are in a commissioning phase over the next 12 months.

So, you are going to continue to see Midwest power demand go up which is going to be beneficial for both East and West.

That was a really thorough and helpful answer. Thanks, guys.

And then if I can ask, I mean I will try to put it delicately in terms of the list of 42 projects and the $6 billion plus, I know some of that is bigger stuff, but even my understanding from your comments that corporate M&A, it’s just not feasible at this point. Specifically, I am thinking obviously about a very recent transaction that was announced, these assets arguably could have fit pretty well, particularly with that vision kind of going coast-to-coast on REX.

Maybe can you just speak to that a bit? I know you did already, but…

Yes. I mean, if you are talking about something that might have been in the Western end of REX as an example, it’s not feasible right.

I have told you all along, I mean I think anybody that is a partner of ours, always has almost call option on that happening. I think there is two things that have to have happen, right.

Yes, I mean, three things, you have to have a willing buyer or willing seller – we obviously would be a very willing buyer and you have to make the math work. And a lot of things where the math works, it’s not – the assets aren’t interesting.

A lot of things where the math does work and the assets are interesting, you don’t necessarily have a willing seller who as an example for whatever reason. And the one I think you are thinking of, without naming it, we were in the talks on that.

It just didn’t happen for us. So, yes and the final thing is, is relative to the 42 and what are good sized numbers I gave you, I told you two of them are projects $1.5 billion a piece, so that’s $3 billion.

That leaves $3 billion. There is no corporate M&A in there.

There is no – there is nothing in there about acquiring one of the smaller MLPs or anything like that.

Appreciate it. And like you said, Dave, its long season.

Appreciate it.

Thank you.

Good afternoon, gentlemen.

Good afternoon.

Fishing here, but want to make sure we exhaust all the possible angles, Dave, on the strong hints of capital deployment to come. Would you care or be willing to kind of just dissect that in terms of either geographic regions or commodities directionally, where the biggest pieces of that puzzle are?

Look, I appreciate the attempt. And kind of I think what I said with Ethan still goes.

But I guess what I can give you is to rate again. I would say that while we have a few of those that are outside of our existing footprint, I think a lot of it is pertinent and assistive to our existing systems.

So, that’s number one. So geographically, just kind of look at where we are at now.

There are a few step-outs where we might go further south, as an example, etcetera. But I think that comment lies there.

I think the second is that – you asked about geography and then you asked about – what was that second thing, commodities?

Commodities.

Commodities. I mean, again, I would only tell you that it’s pretty simple.

If you look at when REX is kind of all-in, if we were consolidating it, we are going to be what half gas, 60% gas, 40% oil, something like that. I think that – it’s a fair presentation of what we are looking at.

I guess I could tell you, there is only one or two things where we are looking at some refined product stuff. So most of it is gas and oil, which is obviously again pertinent to our existing assets.

Beyond that, that’s probably all I think we are willing to give you at this point.

Okay, fair enough. And then actually that’s helpful.

Some more micro questions I guess for you, Bill. One on the REX, the last $150 million a day, is this just the process of matching up – we are seeing delivery points – or requests and seeing what you can come up with in terms of incremental capacity or is it more complex than that?

It’s not much more complex than that. It’s – if we have somebody taking the full $150 million at Clarington wanting to move with the full distance to the end of Zone 3, that’s one level of capacity.

If they are coming in and dropping off in different locations, it just all has to be analyzed, right. And so we are doing that and trying to balance the ins and the outs along with available horsepower and available capacity on the line and it varies based on those pathways.

So, that’s the effort that’s underway currently.

That open season was not binding, right Matt?

Correct.

So that was a nonbinding open season and we are exchanging some documents with one or two bidders in that process. And so it was currently being worked on.

And like Bill said, there is a little bit of complication to it. I will tell you that we are not – I mean, REX has some ability for IT.

Obviously, you have seen that when you tell you as an example that we have run a number of days at 4.5 and 4.6. We may not be able to do that long-term.

We are still assessing that. We – obviously, if we are willing to long-term firm contract $150 million, we hope we can do that.

I guess what I am trying to tell you is there is also a case to be made that a certain slice of IT is very, very valuable on REX at certain points of the year. The max rates in Zone 3 is an example $0.80 a day, a dekatherm day.

So everything Bill said goes, I am just telling you that we are obviously trying to optimize everything.

Alright, thank you. That is it for me.

Thanks, guys.

Thank you.

Yes, good afternoon everyone and thanks for the updates. I am just curious on the Zone 1, Zone 2 you are talking about how you had 45 days at close to 1.8.

Is it now your expectation that, that kind of volume and – or that kind of utilization is going to continue or maybe asked a different way, how long do you think you are just going to be sustained at that kind of utilization level?

We have a guy that runs our engineering group, John. And every time you ask him a question, he says it depends.

And it does depend, right. Is storage full?

Is – we have this bit of late season cold spell that came through the Midwest. That was driving that a little bit.

Storage is refilling. Rockies Gas needs to find its way out.

Rockies Gas is increasing with DJ completions, rigs moving into the powder, etcetera. It depends.

We saw it for 45 days. Do we think that’s a trend that’s going to last for the next 6 years, probably not, but it is telling us that gas can, in circumstances, desire to go from west to east and at a value proposition that is well within our estimated rates post ‘19 and we hope to capitalize on that.

And whether it moves from west to east or east to west, we are going to be able to do that.

Okay. And then what – where is the utilization or what you expect utilization to be the rest of the year on Zones 1 and 2?

Again, John, I need to say the word depends, but we are – we continue to add demand load in the Midwest. We continue to have shippers who want to take it to storage on NGPL on Northern Natural and fill those storages.

That will happen throughout the summer. We saw good load factor in March and April.

And again, it’s hard to predict. We are sold out to the tune of, Matt, 1.4 BCF a day of capacity sold at the original 2006 rates and/or 2009 rates.

And the marketers and the guys who own that capacity are going to use it when it makes sense to do so.

Yes, John, I’d just say just a little differently, because – and Bill is entirely right, maybe just try and put a point on it. We are sold out at 1.4 in Zones 1 and 2, west to east for another 2 – almost 2.5 years.

I mean, we are getting paid whether anything moves or not, okay. Now, I think this is all good news.

This should be good news to everybody here. The actual movements on the pipeline have not been 1.4, but they have been 1.8.

And 1.8 was the initial amounts that were contracted. We had some turn back by Amoco or BP and we had some that has left us by some of the smaller players.

Ultra doesn’t have a current contract, but they will pick up in 2019. So, the point is if you go back and look, the last few years, we have periods of 30, 60, 90, 120 days where we run full.

This 45 days was a little unusual that bodes well for us. We have the other months of the year, so whether that be anywhere from 6 to 10 months a year where we probably some days we run a B a day.

Some days we run 1.3 or 1.4 Bs a day. People should not get caught up in the volumes other than – it just again is an indicator of long-term value for the pipe.

Okay, that’s really helpful. And just the natural follow-up to that is obviously you have got 2.5 years to go at these pretty high levels of subscription.

I mean, any additional insights as far as extending that beyond the 2.5 years on the west end? How – you can share with us, how that’s going?

So, I am going to let Matt answer. But first I will just queue you up a little bit with, we have extended with Encana and Ultra, which is how much and then go from there.

Yes. So, I mean, John I think what we have tried to do successfully as indicated with Encana is we obviously meaningfully face-lifted that contract and pushed that out post 2019 for 5 years.

The Ultra situation, while unfortunate, we worked collaboratively with our management team and we have got a new contract with them for 7 years, starting in 2019. So we are already 700 million a day of 1.8 BCF, that’s already subscribed.

So what I would tell you is it’s not as if the pipe is going to be empty at the end of 2019. We have already done a tremendous job of making sure that the EBITDA had as much visibility through 2024 as possible.

And I think those slides are available publicly. So I would refer to those.

I think what you are seeing some with REX and we are making announcements which I think is particularly important for folks on demand load that we are adding to the system, interconnects we are adding, power plants, etcetera. All of that is value enhancing for our west to east value proposition for customers down the road then.

And when we talk about REX and moving gas west and moving gas from the west to east and the east to west, we want to provide optionality for folks both coming in, in the east and coming in, in the west to jump off at different points. And it’s going to move based on weather and different demand loads, but really the optionality that we are building in for our Rockies folks, so they can go over thrust into opal or they can come, take a turn to the east and then go to the power plants and so forth in the Midwest.

As much demand load as possible is long-term how we are going to continue to create value for our customers and keep as many of them as possible. Hopefully, at attractive transportation rates post 2019, recognizing that we have already sold out 700 million a day of our capacity.

And John, it’s worth noting that the 700 million a day that is sold out post 2019 is greater than historical basis, foreseen basis or any predictive model that anybody has run in terms of a unit rate per dekatherm for that 700 million a day. So we are significantly ahead of the game on post 2019 re-contracting effort already and I think making up innings 8 and 9 to use Dave’s baseball reference, we are so far ahead hopefully our relief pitcher can just hang in there and keep us with the win and that’s our intent.

That’s super helpful. Thanks for that.

Thanks for the remainder on the contract extensions won to-date? That’s it for me.

Thanks, John.

Hey, guys. My questions have been addressed.

Thank you.

Mike. Come on, Mike.

Come up with another one. Do you already hang out?

Okay.

Thank you. So just kind of going back to the 42 projects, I think you said north of $6 billion.

And so when we think about that, can you just talk about sort of maybe sort of what embedded multiples are in there? And then also if you could, I don’t know if you can bifurcate it or break it down to something that might be 1 to 2 years, 1 year to bring online.

Some projects we are looking at 18 months, that kind of thing?

Yes. And I think we can help with both of those things.

I would say that given your range of kind of 5x to 7x distributable cash flow multiples is kind of what’s in the bag for – so when I said 42, you take out 2 that’s 40. I said $1.5 billion, you I think kind of 5x to 7x would be a range.

I mean and some of them are going to be 10s, right and some of them are going to be 3s. So 5x to 7x is kind of the answer to your first question.

I think relative to timeframe, so again the way I kind of think about that is if you are just concentrating on the $1.5 billion and not the big projects, which would probably entail some regulatory time needing to burn off, which is not insignificant. I think I already told you, we are hoping a couple of $100 million in next 0.5 year here.

So, let’s – and I don’t know say you take off $250 million off of that, so that gets you 6 months out. And again, a lot of that could happen even faster than that, but now you are dealing with $1.250 billion.

I guess I would think fully all of it placed in-service generating revenue EBITDA, cash flow for us maybe all-in 3 to 4 years, starting this moment.

Thanks very much.

Well, as always, thank you everybody. Thank you guys for the questions and thank you for everybody to tuned in both on the call and on the web.

Really appreciate your support and interest in our company and hope everybody has a great evening. Thank you.