NGL Energy Partners LP (NGL) 2017 Q3 法說會逐字稿

Good day ladies and gentlemen and welcome to the NGL Energy Partners Q3 2017 earnings conference call.

(Operator Instructions)

As a reminder, today's conference call is being recorded. I would now like to turn the conference over to Chief Executive Officer, Mike Krimbill; and Chief Financial Officer, Trey Karlovich. Please go ahead.

Thank you Candace. This is Trey, good morning and welcome. This conference call includes forward-looking statements and information. While NGL Energy Partners believes that its expectations are based on reasonable assumptions, there can be know assurance that such expectations will prove to be correct.

A number of factors could cause actual results to differ materially from the projections, anticipated results or other expectations included in the forward-looking statements. These factors include prices and market demand for natural gas, natural gas liquids and crude oil, level of production of crude oil and natural gas, the effect of weather conditions on demand for oil, natural gas and natural gas liquids and the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to financial results and to successfully integrate acquired assets and businesses.

Other factors that could impact these for looking statements are described in risk factors in the partnership's annual report on Form 10-K, quarterly reports on Form 10-Q and other public filings and press releases. NGL Energy Partners undertakes no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. Please also see the Partnership's website at, www.nglenergypartners.com, under investor relations for reconciliations of differences between any non-GAAP measures discussed on this conference call to the most directly comparable GAAP financial measures.

At this time, I will turn the call over to Mike Krimbill for opening remarks.

Thank you Trey. Good morning and thanks for joining us today. First, I would like to say the theme at NGL is, nothing has changed.

The sector has emerged from the recent challenges and there is significant upside to our business. Obsessing over a quarter's numbers, rather than the next three to four years projected EBITDA, just does not make any sense. With respect to distribution guidance, we continue to expect a 20% increase in our distribution over the next four quarters and 10% annually thereafter, for the next three years.

On Grand Mesa, we began shipping in November as you know. We had one committed producer that was having some difficulties. The situation with that producer has been clarified.

We began receiving 100% of that producers production volumes January 1 and we have agreed upon a term sheet for the next seven to 12 years. We are also picking up additional volumes from non-committed producers in the northern portion of the DJ. The DJ rig count is up significantly, which will bring us increased volumes and wider spreads as FY18 progresses.

We purchased the Murphy Energy assets in January for approximately $50 million at a five-times multiple. We're integrating those currently. Bringing back former customers that had left because of Murphy's financial situation.

In evaluating an expansion of the Kingfisher assets. The STACK extension was announced and will be completed this calendar year. This provides NGL the presence in two of the three highest rated return basins -- the DJ and the STACK.

We're currently looking at the Permian like many others, to find an opportunity that does not come at a 12 to 20 multiple. In short, the future is very bright, we are at the bottom of this current cycle. There is significant upside to our water disposal business and crude logistics, with the increased rig count in the DJ and Permian which we all seeing and to a lesser extent in the other basin such as the Eagle Ford.

We have transitioned NGL into a higher fee-based repeatable business model, with our recent organic projects. Our balance sheet is much stronger and common unit coverage high. With that I would like to turn back to Trey for his comments.

Thanks Mike. I appreciate everybody joining us this morning. I'll be going over our financial results for the third quarter which were released this morning, as well some of our thoughts about the rest of this fiscal year and beyond.

On our last call, we discussed the notes offering which we closed in October and is now reflected in the financial statement. This offering was significant in that allowed us to balance out our secured and unsecured borrowings and increase our liquidity. It also extended the debt maturities to November 2023.

Since then, we have seen a new president elected, an agreement by OPEC to limit production, an increase in the stock market in interest rates, as well as, dare I say, some stability in oil price; although the past couple days may not reflect that. We've also announced the Murphy and STACK projects. As Mike discussed, it has some resolution on Grand Mesa producers and gave our distribution guidance in the middle of January.

As a result, the notes that we issued in October are trading well above par, which is great to see. We continue to be pleased with the transaction and the continued transformation of our balance sheet. As we've discussed over the past several months, our financing strategy has been to reduce our committed capital requirements, decrease our leverage, increase liquidity, improve access to capital markets, all of which we have achieved.

This continues to be our focus, as well as extending debt maturities and balancing the financing of our capital expenditures going forward. Happy to announce that we have launched an amendment and extension to our credit facility and we hope to have it completed in the short term.

We expect to continue to utilize our ATM to fund a portion of our various growth opportunities and I'm happy to report that we have financed approximately 50% of the growth capital expenditures from this past quarter with proceeds from our ATM. We expect the same for the upcoming period as well.

Our total growth in acquisition capital expenditures is totaled $416 million through 12/31 and including the recent Murphy acquisition, we expect growth capital to total $475 million for FY17. We have a minimal amount of CapEx committed for FY18 and are currently running our model with only $100 million of CapEx for next year.

Let's go through some details of our results. Our operating income for the quarter was about $23 million which includes $61 million of depreciation and amortization expense. We generated approximately $121 million of adjusted EBITDA this quarter and have reported approximately $260 million year to date.

Our quarterly results include the following impacts. A two-month delay in volumes from Bonanza Creek on the Grand Mesa pipeline has impacted us by about $5 million. We do expect to make this up through increased volumes in FY18 and the contract remains seven years with a start date of January 1, 2017, instead of November 1, 2016. We continue to expect Grand Mesa to contribute $120 million of adjusted EBITDA in year-one and $150 million in year-two, based on the contract start of November 1.

A late start to winter heating season had an estimated $3 million to $4 million impact on the current quarter between our retail and wholesale propane businesses. A portion of which could be made up with a decent February and March.

The water segment results were slightly under our forecast as we were impacted by lower skim oil recovered and approximately $40 hedges we had in place, at the higher forecasted volumes. This was an approximately $1 million to $2 million impact on the quarter and as a reminder; we do not currently have any significant hedge positions in place going forward and should benefit directly from the higher crude price in the current quarter.

The crude logistics business continues to face margin competition, particularly in the basins where drilling activity and production continues to decrease. We do expect to see better performance from this business going forward with the new assets coming online, stabilizing of the crude market and increasing rig counts in our core basins. Additionally, we have begun leasing more of our storage capacity to third-parties and receiving fee revenues rather than utilizing our own storage for contango, which should lead to more stable and predictable cash flows going forward.

Going through each segment in a little more detail, our refined products segment continues to exceed our original expectations for this fiscal year. This quarter was expected to be a lower EBITDA producing period as the gasoline curve moves with winter blending season and impacts our inventory valuations. We have built inventory during this period and we are well positioned from an inventory standpoint for the fourth quarter.

We generated approximately $30 million of adjusted EBITDA in this business segment during the quarter and $113 million year to date. Similar to last year, we expect a very successful fourth quarter in the refined business, as we continue to grow with our customers along the Colonial and Plantation pipelines. We're currently expecting this segment to generate approximately $160 million of adjusted EBITDA for the fiscal year.

The fundamentals of our water business have improved throughout the year as volumes continue to grow and demand for disposal increases as well. We recognize adjusted EBITDA of $17 million for the quarter, which as I noted was impacted by the hedges we had in place. Overall volumes are slightly lower than our original expectations but they have grown 3% since last quarter and we're expecting continued growth this upcoming quarter, as well as through next year, driven by higher rig counts and additional flowback volumes.

We're expecting our DJ Basin business to benefit from the -- in the upcoming quarters from additional drilling activity and new water customers. We continue to see robust drilling and production in the Permian, specifically in the Delaware. We are investing in some new infrastructure and focusing on pipeline gathering of the disposal water.

We see signs of improvement in the Eagle Ford as well, with an expectation that drilling activity will increase as we inch closer to $60 crude prices. At this point in time, we're expecting this business to come in slightly under our guidance and are now targeting $65 million to $70 million for the full year, with an exit run rate of $80 million or higher.

The Crude Logistics business generated about $17 million of adjusted EBITDA during the quarter, with Grand Mesa operational for two months and contributing a majority of the EBITDA for the segment. The [other] assets performed okay during the quarter but at the expense of our Marketing Division, which continues to struggle in the current environment and supplements the various assets.

We have and continue to focus a significant amount of attention on this business segment and with the recent startup of the Houma terminal and the upcoming terminal at the Port of Point Comfort, we do expect improvement. Grand Mesa [loans] should produce $30 million in the upcoming quarter and over $130 million next year.

With Houma operational and assuming crude stays in the mid-$50 range, our current expectations for the crude marketing and logistics businesses is between $65 million and $70 million of adjusted EBITDA for the year. Looking ahead to next year, we expect the segment to contribute over 25% of our EBITDA, with Grand Mesa again contributing around $130 million to the bottom line.

Retail propane generated about $32 million of adjusted EBITDA for the quarter, in comparison to $23 million during the same quarter last year. A small portion of this growth is related to our acquisitions, but generally speaking, they are over 20% better compared to last year. December was a very good month and January started well, but has seen a warm up over the past couple of weeks in certain areas.

Recent data projects slightly warmer than normal temperatures in the upper Midwest, with slightly colder than normal temperatures in the Northeast; the areas we have most of our propane locations. We continue to expect an overall normal February-March which should bring us in line with our guidance of $105 million for the year. Rising propane prices may have a slight impact to retail margins over the next couple of months.

We expect this to be minimal and to be recovered as prices stabilize. I will reiterate, we're basing this guidance on normal winter weather and corresponding volumes in our operating areas over the next couple of months.

Finally, our liquids segment performed mostly in line with our recent guidance. With our wholesale propane business slightly outperforming budget and our butane business coming in slightly below as an offset, as it continues to carry the burden on high cost railcar leases. We have over 850 cars with leases expiring in 2017.

Those cars have an annual cost in excess of $9 million. A portion of which will be returned and others which will be renewed at much lower rates going forward.

The Sawtooth Storage Facility remains under plan, however we're making progress on contracting for the upcoming storage season, which should benefit next fiscal year. The assets from the recent Murphy acquisition will be included in this business segment going forward, beginning with this upcoming quarter.

Our Liquids logistics business generated approximately $26 million in EBITDA this quarter and has generated $47 million year to date. The wholesale propane business is expected to benefit from rising propane prices, which would more than offset any impact seen on the retail side. We're currently forecasting $85 million to $90 million of adjusted EBITDA for the Liquids logistics for the entire fiscal year.

We expect growth in this business next year with the new assets at Port Hudson and Kingfisher, increased utilization of Sawtooth and a reduced burden from railcar leases. Overall, we expect to be at the low end of our guidance -- EBITDA guidance for the FY17. Our distributable cash flow for the quarter was $85 million and has totaled approximately $280 million for the past 12 months, resulting in a TTM coverage of about 1.5 times.

We expect this trailing month coverage to continue to increase to 1.6 times next quarter, with an expected distribution increase to $0.44 per unit, per our guidance. And we expect to stay approximately 1.6 times covered next year, as we increase the distribution to $2 per unit annualized, a 28% increase over last year.

We're targeting to cover our distributions in every fiscal quarter going forward and beyond FY18. We expect to grow the distribution approximately 10% per year; thereafter, while maintaining coverage between 1.3 to 1.5 times. This includes the distributions to our class A preferred units and our excess cash flow will be used to fund our organic growth opportunities and continue to delever the company.

Looking at the balance sheet, we continue to target compliance leverage of less than 4 times by year end, compared to our covenant level of 4.75 times. The pro forma adjustments to compliance EBITDA, continue to reduce and will reduce even more rapidly with the start up of Grand Mesa. As I mentioned, we are working on an amendment and extension to our credit facility and our core bank group has been very supportive through the process.

We hope to announce that extension in the near future. We have reiterated numerous times in the past; we are targeting compliance leverage of [3.25] or better, which we are expecting to achieve at the end of FY18 or next March and will continue to manage our business with that target in mind. These leverage metrics excludes our working capital facility, which is governed by a monthly borrowing base determined by our receivables and inventories.

This facility was approximately $875 million at 12/31/16 as our inventories are seasonal highs and commodity prices have risen over the past few months. The balance is expected to decrease significantly by the end of this fiscal year as we reduce inventories.

As a reminder, this facility is excluded from our covenant calculations. In summary, (technical difficulty) we're excited about the future of our businesses and the position we are in today.

We have significant cash-flow growth. Next year, with a full year of Grand Mesa, Houma, Collins, additional Colonial alliance space, Point Comfort, and increasing rig counts, increased higher crude prices and continued focus on full utilization of our assets.

We will continue to focus on our balance sheet, safely operating our assets and growing our businesses in a prudent and thoughtful manner. We appreciate your interest and support and we look forward to seeing and speaking to many of you in the near future. Candace we would now like to open the line for questions.

(Operator Instructions)

Robert Balsamo, FBR.

Quick clarification. I know you just mentioned next year, your expectations for coverage for FY18. Did you say 1.6 times, 1.3, to 1.5 over the longer term?

Our target range is 1.3 to 1.5 times. We expect next year's coverage to be closer to 1.6 times.

Could you talk a little bit about the range? The guidance last quarter was unofficial for 2018. Could you talk a little bit about that, that you were saying over $600 million. It sounds like that would roughly still be in-line given that coverage number but could you speak to that, if you can?

We have no change to that at this point in time. We're working on finalizing our budgets for next fiscal year and update our forecast, thereafter. We do not expect it to be any -- significantly different and we will give robust EBITDA guidance by business in our next quarterly call.

Just to clarify that. Some of the acquisitions were announced after last quarters guidance, so that now be including some of these acquisitions and offsetting some of the weakness? Is that incremental?

The acquisitions should be incremental to what we spoke about last quarter.

Darren Horowitz, Raymond James.

If I could, I wanted to go back first to the discussion around the purchase of the terminal in Kingfisher County and the opportunities to expand those assets like you referenced. Do you think it is more of a wide grade opportunity to Conway via Chism or maybe some splitter opportunities?

If you could talk also, about what you see as incremental CapEx associated with those expansions and where you think expected returns could be? That would be great.

It is more on the Kingfisher, the condensate, the project perhaps to remove sulfur from the off-spec condensate. In our model, we only assumed 1,400 barrels a day of condensate and the splitter will handle 5,000, which probably means we can do 4,000 efficiently.

On the other side, we assumed 4,000 barrels a day of Y-Grade and I believe the capacity is, at the moment 7,000. I don't have a number on CapEx but it's not going to be much.

Also Mike, regarding the purchase of the Port Hudson terminal. You outlined the expected EBITDA run rate there.

Where do you see more opportunities to drive value? Is there more of a butane blended opportunity or maybe additional downstream opportunities to leverage security products?

At the moment we're supplying butane [and that's] to a single customer who has built storage. It may be a lease of storage on the Colonial Pipeline Property there, so I think we're not seeing -- that we will have a big increase in supply but there may be an opportunity to expand the facility. Meaning more storage and then perhaps more blending.

My last question, more of a clarification. Can you guys provide how much storage at this point, you have leased to third parties on a fee-based perspective relative to how much you are using for Contango storage, just so we have a sense?

We have -- on the crude side, we have just under 1 million barrels that we're utilizing for our own usage. The remainder of the capacity is being leased to third parties.

Michael Blum, Wells Fargo.

I guess a couple of segments I wanted to talk about. One, in the water business, the water segment.

You referenced the pickup in drilling activity but will you talk about effectively; when does that translate into stronger results in that segment? And you also referenced that, effectively skim oil was a drag on the business year over year. When does, at this point, prices are higher, so what point does that become a benefit and not a drag?

I'll start with the volume. What we are seeing, there is a lag so the rig account increases in an area, such as the Eagle Ford, we have excess capacity. We see that benefit immediately but the majority of the increase is happening in the DJ and more so in the Permian in the Delaware side.

We are out buying properties and filing for permits currently, so we would expect to see our water volumes increase in say, late summer, just to be safe. We will have a higher percentage of flowback, so we should see our skim oil percentage increase also and get the benefit -- currently we're getting the benefit in this January, February, March quarter of higher prices because we don't have the hedges we did in the low $40 range.

We are also seeing a big uptick in solids, we have solids processing facilities. DJ and the Eagle Ford in particular. We are very excited about what is going to happen, by say, late summer and then the third-fiscal quarter with October, November, December, 2018 from the increase recount.

In the DJ, we have capacity there, so we are not drilling any additional wells. We may drill one for one of our committed producers. So all of the increases is just falling right to the bottom line.

We think we're going to be full in the southern half of the basin by the end of the summer and then northern half will probably take a little longer to fill up. Our capacity there is about 220,000 barrels a day and we are approaching 100,000 and it will just keep increasing from there.

We also just opened our two facilities there, C6 and C9, that process solids. We're seeing an increase in the solids as well because of the increased drilling.

Michael, on the skim oil, just to put some frame of reference around it, we expected a little bit less than 2,500 barrels a day of skim oil in our forecast. We came in just under 2,000 barrels a day. We have hedged close to that 2,500 barrels a day at $40, so -- our hedges were in excess of the actual production at a lower value in a rising price environment.

Overall that was about a $1 million to $2 million impact to the quarter. Taking that impact away of just the hedges being -- the over hedges and then removing hedges and assuming the mid-$50 price, that bridges -- that alone bridges a gap between the $17 million for the quarter and the expected run rate next year -- next quarter of $20 million at least.

In the liquid segment, the wholesale basically business -- is it just weather that is driving the change in that -- in the margins in particular? Just trying to understand the change in margins; and I think volumes I am assuming is weather but just wanted to make sure I understood the dynamics there.

Most of that margin change is on the butane side of the business. That was expected coming into the year. Part of that with increased rail costs, increased competition in basins because of excess railcar capacity.

All of that has driven to the impact that we're seeing on the butane side of the business. The wholesale propane business margins were not significantly different than what we have seen in the past.

Final question. I apologize if you said this and I missed it. I got all of the segments but could not add them up quickly enough. Is the prior guidance for this fiscal year was [$485] million to $500 million? Where does that stand now?

We will be at the lower end of that range.

Matt Niblack, HITE.

In terms of the overall trajectory of the water business, it is definitely running, obviously a bit below where you had originally hoped. When you look forward to 9 to 12 months from now, by the time you have these new wells -- new wells online and you have laid some more of the pipe that you need to lay in places like the Delaware do you have a sense of volume and/or EBITDA that you expect to be at if current trends continue in that 6 to 12 months from now range?

Yes. What we did is looked. We modeled it and then we said -- what does it take to get to an EBITDA of say $125 million? And at that level, we only need about 700,000 barrels a day of water. We're in the low 500's. I do not know what -- we are coming out of this year on a run rate but it should be more than that.

Then you said, can we get 100,000 barrels a day, each year, for the next two years and clearly the answer is yes. In the Permian alone, if you are doing 30,000 barrels a day per well, that is only seven wells.

That is only water -- let's say 3 to 4 [to] 1 ratio. That is adding 3 or 4 million barrels a day of water that needs to be disposed. We're being very conservative because we've gotten beat up on this water thing until here recently. But it looks fairly simple to get up well over $100 million of EBITDA.

As a run rate by -- end of this calendar year, roughly?

The permits have to get approved, that takes a number of months. So if we had ten drilled by the end of the year, then maybe we only get half a year's volume. I think conservatively we would say at the end of two years. So count end of calendar 2018.

In terms of the competition in this business. How is that evolving? Is it getting more competitive, less competitive and how do you build a moat around this business?

That is a great question. In fact, we had a discussion yesterday because we all looked around and said who are the competitors? We know who they were in the future -- in the past you had [Piod] and Select and Key in Basic and they've all had some issues. We have seen a few new entrants but I actually talked to the water guys yesterday and we went through who the competitors were in each basin.

We have competitors that have anywhere from one to five, six, seven, eight wells, SWD. We do not have a large competitor out there.

We have heard Western wants to get in and do Anadarkos. Anadarko does some of there own, so there is plenty of room for both of us.

We don't have a large competitor and it is really basin specific and you have these smaller guys. We have 80 plus disposal wells, so we are 10 times larger than most of our competitors, if not all.

I don't see prices falling any further. I think they have gotten as skinny as they are going to. We hear that some of the oil-field service companies are beginning to raise their prices and perhaps producers are racing to lock in rig costs as soon as they can, so they do not have that increase.

We do not see any further decline. We have a menu of services to bring, not just water disposal. I think public companies should be more interested in dealing with us because we are going to be very safe, take (technical difficulty) the risk that they do not want to take.

I sit here sometimes wondering, why we're not getting all of the business because our model is really, I think, significantly ahead of the competition.

In your build out there continues to be mostly pipelines for the incremental volumes?

No. I think we're seeing pipelines, I'm not sure how much, 100,000 or 200,000 barrels a day of new pipeline -- water. I think if you go into the Permian and you are able, there is a new area they are drilling.

It is easier perhaps to just start with a pipeline instead of trying to convert an area that is already producing to a pipeline so I think we're having good success in the Permian. I do not know if it is 50/50 between new water or new pipe versus truck.

Last question. You've seem to have had some success getting some acquisitions here that fit nicely with your system. Do you see that continuing? Is there still a nice backlog of opportunities there that should [see] that activity?

On the water side?

Not necessarily, just the water -- so you could comment by business but you made some nice [termline] acquisitions, you made some tuck-in acquisitions in propane; so I guess when you look at the different businesses, what is the outlook for continuing to do those kinds of tuck-in acquisitions?

On the retail propane side, it is all tuck-in, we're not doing any startups there. They tend to lose money for two to three years. They are just buying at a four to six multiple, based on projected, not trailing.

The other segments we're really, completely focused on organic projects. We think there is growth to be had at Port Comfort, Houma, certainly I think in the DJ, STACK. Our refined products we're looking to see if we can build storage with partners.

I don't see M&A, as a -- it's not a focus and I don't see it being outside retail propane, having a high probability. Like you said the Murphy assets; we were familiar with those and we engaged Murphy Energy for a number of months and then they unfortunately had to file for bankruptcy but that is probably a one-off type situation.

(Operator Instructions)

T.J. Schultz, RBC Capital Markets.

I have really just one question, it is a follow-up to Matt's last question on CapEx. You have, I think you said, $100 million of growth CapEx for FY18 in your model.

On your last point there Mike, really the focus is, organic growth. Maybe if you could just characterize where there are the most options to increase that spend in 2018. What is the timing for the Point Comfort spend, in particular and just where the most opportunities are on the growth side?

I will start. On the water side, we assumed about $50 million of CapEx, that is about 10 wells in this fiscal year, $50 million of that $100 million. We have the STACK which is $25 million to $30 million, I think we had [$5 million] left in Point Comfort. On the water side we don't really see any -- in fact we don't see any acquisitions.

Where they are in crude, we would love to find something that make sense in the Permian. We would like to see some extensions or gathering systems both in the DJ and in the STACK. Those are possibilities.

Point Comfort would be bringing additional volumes through that whether it is by pipe -- I think that is probably the biggest opportunity there. Then, on Houma, we'd just be expanding storage, so -- we're running the facility, it is in service, it is going well.

We're expecting or hoping; I'm expecting, everyone else is probably hoping for increase storage that we can build there. The -- I think liquids were focused more on [teeth] drives. We recently signed a contract with a customer for five years and we have other discussions going.

The great thing there is you do not have any CapEx. We get to use -- more fully utilize our realtor fleet There's always some small propane deals and then refined products we're looking to build storage with others and utilize that storage like we do at Collins. (multiple speakers)

T.J., on Point Comfort, some of that spend will be in this current quarter and then a little bit rolls over into next year. Only $5 million.

That rolls into next year?

Yes.

Sunil Sibal, Seaport Global.

Most of my questions have been answered. I was looking for housekeeping item. What was the covenant leverage at the end of the quarter?

Covenant leverage at the end of the quarter is close to [four five] -- with the pro formas.

Then you expect to end FY18 at four times correct?

Yes, that is the target. That leverage comes down pretty quickly with -- this is the quarter that we generate significant excess cash flow which will reduce the amount of debt outstanding. We have very little CapEx to spend during this quarter and we will get the full benefit of a quarter of Grand Mesa.

Basically then we're looking at FY18 and your reported leverage and [covered] leverage should be pretty much aligning correct?

Other than the exclusion of the working capital facilities. The pro forma EBITDA comes down significantly over the next two to three quarters.

Ray Fu, Bank of America.

A quick clarifying question on the (inaudible) volumes for the DJ and Grand Mesa. Is it comparable to the guidance which seems to be unchanged and also on Grand Mesa how does the agreement with Bonanza Creek stack up to the prior expectations?

The guidance on Grand Mesa does not change. If you go back when we provided that guidance in April of last year, we took the volumes from Bonanza and reduced those in half in our guidance.

We reduced that from a 15,000 barrel commitment, which they had disclosed to a 7,500 barrel a day commitment. They're currently producing more than that and we received 100% of their volumes and they are expected to complete some wells, as well as bring a drilling rig back in after they complete their bankruptcy. At that point in time, we would expect to see volume growth through the remainder of this year.

Our expectation is that with that growth, we would still end up at the same overall impact as what we had guided to by reducing our volumes in half and they would exit a higher run rate than what we had forecasted for next year. Their rate is disclosed in their filing -- tariff is in line -- there are some ancillary transportation that they would be provided but that rate does have an escalator based on crude price.

Our assumption for crude price is something very much in line with what we're seeing today in the mid-$50 range. They are the only producer that has a rate that is dictated by crude price. They have -- it does have a floor and the floor escalates after a couple of years.

On the crude logistics -- on the comment that you expected to make up 25% of next year's EBITDA, next fiscal year's EBITDA. Does that make any assumptions regarding the forward curve in Contango or is it more or less just assuming that today's conditions persist.

Today's conditions -- again rough math, our numbers from last quarter, if we assume $600 million-ish, $150 million from crude, $130 million of that Grand Mesa. Again, at least 25%.

Final question, can you just clarify, you guys are sticking with the FY18 EBITDA guidance for now?

For FY18, yes. We used, again some round numbers last quarter.

We will give more robust FY18 guidance on the next quarterly call. And we will break that down by segment as well.

Matt Niblack, HITE.

On the crude logistics business, it looks like this is the biggest guide down versus your prior guidance. I'm trying to understand that Delta.

How much of that, if any, is Bonanza Creek? Is it $5 million or is it zero and then is the rest mostly the evaporation of Contango?

Bonanza Creek was the $5 million which we referenced in the call. (multiple speakers)

Do think you're going to make that up?

We will make that up through the rest of the contract year, yes, that is our expectation. The rest is in our marketing business which includes supporting our trucking, our marine, our wellhead business, as well as our storage business at Cushing and various other terminals.

There are no further questions at this time. I would like to turn the conference back over to Mr. Krimbill for any closing remarks.

Thank you very much and we will talk to you soon.

Ladies and gentlemen thank you for participating in today's conference. This does conclude the program and you may all disconnect. Have a great day everyone.