NGL Energy Partners LP (NGL) Q1 2018 Earnings Report, Transcript and Summary

Good morning ladies and gentlemen, and welcome to the Q1 2018 NGL Energy Partners LP Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host, Mr. Trey Karlovich, CFO.

Thank you, Kenzie and welcome. This conference call includes forward-looking statements and information. Words such as anticipate, project, expect, plan, goal, forecast, intend, could, believe, may, and similar expressions and statements are intended to identify forward-looking statements. While management believes that its expectations are based on reasonable assumptions, there can be no 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, liquids, refined products and crude oil; level of production of crude oil, natural gas liquids and natural gas; the effect of weather conditions on demand for oil and natural gas and natural gas liquids; and the ability to successfully identify and consummate growth opportunities and strategic acquisitions at costs that are accretive to financial results and to successfully integrate and operate assets and businesses that are built or acquired. Other factors that could impact these forward-looking statements are described in the Risk Factors and 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. This conference call also include certain non-GAAP measures, namely EBITDA, adjusted EBITDA, and distributable cash flow which management believes are useful in evaluating our financial results. Please see the partnerships earnings release, investor presentations, and annual and quarterly reports on Form 10-K and Form 10-Q on our website at www.nglenergypartners.com under Investor Relations for more information on our use of non-GAAP measures, as well as reconciliations of differences between any non-GAAP measures discussed on this conference call and the most directly comparable GAAP financial measures. At this time, we will now turn the call over to Mike Krimbill, our CEO.

Thanks, Trey. I think what I'd like to cover and then we'll get into detail. However Trey is in overall state of the numbers and the company -- have we changed any strategies based on the market conditions; and then my thoughts on the individual business units in the full year. So I think first we need to put the quarter into perspective. Our NGL logistics segment was about $10 million of the shortfall due to falling liquids prices during the quarter. Our inventory values include our pre-sold gallons that are at a higher price than the quarterly average, so prices were declining from April through the end of June such that when the ratable barrels we received each day are sold and they are sold at or above cost, they are hit temporarily with a higher weigh [ph] resulting in a loss. So this shifts the EBITDA into future quarters when the presold gallons are extra delivered, so this is a timing issue. We've had this happen to us in the past and in the summer when the liquids prices were falling. Secondly, our refined products group also experienced some timing issues. Our hedges of the future months product prices did not match the decline in the twelve [ph] month; the twelve months fell more than the out-months and that resulted in a loss of approximately $15 million that will be recovered prior to year end as the prompt and future months prices converge. Adding these two items back to EBITDA which resulted in a number of the low $60 million area which is about $10 million below the equity analyst average guidance. This $10 million in trial get into I think some more -- it will not come back as it resulted from the same market conditions we experienced in the fourth quarter of last year. Our analyst average guidance for the year continues to be accurate based on current market conditions. Here into July and early August, liquid prices have increased in particular propane and butane over $0.10 a gallon which will pull some of that liquid shortfall into the second quarter. So now we have a higher turn price than our inventory cost. We're also experiencing a greater increase in the refined products twelve month prices, so the future hedged month higher than -- it's gone up more than the future months has, so this will pull a portion of their fine product timing issue into the second quarter as well. Strategically, we have modified our refined products business to no longer be exposed to negative line space values. We have renegotiated our marketing contracts effective July 1 and we've stopped shipping on our line space to the extent of discretionary when values are negative. And we have purchased other shippers line space when those values are negative which means they pay us to ship on their space; so the bleeding has stopped. Now I'd like to provide an overview of each segment. Water solutions, the results are ahead of plan. Our excess capacity is the real advantage, especially with the increase in the drilling and the water ratio in the Delaware. Water disposal volumes averaged 624,000 barrels per day in the first quarter with all basins experiencing significant increases other than Eagle Ford which was flat to a little up. Our previous guidance for the entire fiscal year assumed only 643,000 barrels a day, so we're already about -- within 20,000 barrels of the entire year and we're seeing increasing demand from producers, particularly in the Delaware. This 643,000 assumption, we will certainly exceed for the year. We also continue to reduce expenses and of course emphasize the water pipelines. Crude oil logistics, the key asset here is obviously the grand mix of pipeline, we based our previous guidance on 80,000 barrels a day but for the year we anticipate nearly 100,000 barrels a day by the end of the year and maybe close to that by the end of September. Retail propane were up -- pleased with the performance in the segment, we achieved our EBITDA plan and beat the prior year's volumes and financial results. Liquids, here we have the timing issue of when EBITDA is recognized but our propane volumes increased 10% over the prior year. Butane volumes declined about 5% and other product volumes increased about 14%. So our total volumes are increasing and the EBITDA will follow. Refined products; we have modified the way we conduct the discretionary line space portion of our business as I've said we've renegotiated the marketing contracts among other initiatives. We're also pursuing other revenue streams and remain committed to the pipeline as the most cost effective transportation to supply the southeast and east coast with fine products. We remain focused on our balance sheet with greatly reduced debt leverage as our goal. We're looking at the possibility of monetizing certain assets as a way of achieving this goal faster. As you know, we have been successful at this numerous times in the past two years beginning with the merger with Saddlehorn to reduce capital requirements and most recently with the Oaktree preferred investment. So with that I'd like to turn it back to Trey.

Alright, thanks Mike. So I'm going to go through our quarterly results as well as our current expectations for the rest of this year with my additional thoughts on each business segment. So walk through each segment expectations for the remainder of the year and then we'll go through the balance sheet. I'll start with the easy ones, so with crude oil. The crude segment generated approximately $26 million of adjusted EBITDA this quarter with Grand Mesa contributing $30 million and the remainder of the segment operating at a slight loss as the marketing business continues to support our various assets. Volumes on Grand Mesa averaged about 75,000 barrels per day for the quarter and exceed the quarter over 80,000 barrels per day. We expect volumes to continue to ramp through the upcoming quarter and we expect over 90,000 barrels per day in August based on current nominations compared to our original guidance just for this quarter of 75,000 barrels per day and an average of 80,000 barrels per day for the entire year as Mike mentioned. As a reminder, the minimum volume commitments on the pipeline increased on November 1. The differential in the basin continues to improve, that is currently trending ahead of our original forecast. Our Houma and Point Comfort assets are just beginning to ramp up and we expect those assets to generate incremental revenues throughout this year. We continue to focus on rig counts in the basins we operate, crude prices and opportunities for increased utilization of our transportation and storage assets. And the crude group is working closely with our water team to provide multiple services to producers. The Glass Mountain extension into the stack remains on budget and on-schedule and we continue to expect it to begin operations in early 2018. At this time we are forecasting the crude segment to generate approximately $125 million of adjusted EBITDA for the fiscal year. Moving to water; as Mike mentioned, water volumes continue to grow at a steady pace as we experienced an increase of over 16% from the fiscal fourth quarter. This growth was above our original expectations and resulted in approximately $22 million of adjusted EBITDA for the water segment. The growth has been across each basin in which we operate and we continue to expect growth throughout the remainder of this year based on our assumption that crude oil prices remained around the current levels and drilling activity does not decline in the Permian, DJ, Eagle Ford or Bakken. We continue to add new customers as water disposal remains the higher priority for EMPs, particularly in the Delaware and the DJ. We've invested approximately $35 million of growth CapEx this quarter in the water business. We are forecasting water to generate approximately $105 million of adjusted EBITDA for the fiscal year driven by a continued increase in volumes and current crude oil prices. We are not anticipating any longer term oil pricing declines which could impact rig activity. In these significant move in rig activity, up or down, would impact our volume assumptions. We have also hedged approximately 25% to 30% of our expected oil production at about $49.50 per barrel from August through March 2018 to limit any direct impact from crude oil pricing changes. Moving to liquids; the liquid segment essentially broke even in this quarter posting a small-off of $1 million. As Mike mentioned, the wholesale propane business was below budget as a result of declining propane prices versus an inventory cost that included product and storage costs for pre-sold gallons. However, we expect to make up most of that in the remainder of the year based on current inventory values, pre-sales already in place and the expected lower [indiscernible] going forward. The butane business also operated at breakeven levels and while we continue to manage an oversupply of rail cars, a portion of our fleet has and additional cars will be coming off-lease which will reduce costs going forward. We expect much improved utilization of our fleet going forward which will increase margins for the remainder of the year. The majority of EBITDA for this business is expected in the second and third fiscal quarters. Our Sawtooth storage business continues to operate below plan as many customers and potential customers are utilizing real storage and move the caverns. We're continuing to work on additional contracts for the storage season which we need to be in place by September timeframe to benefit this year. Based on the current contracts in place for storage, we are lowering our EBITDA guidance for this segment slightly to $85 million for the fiscal year. Retail propane EBITDA was about $7 million, right in-line with our budget; this includes all the acquisitions that were completed mid-2016 which increased volumes but also increased operating cost as we had some additional one-time integration expenses during the period compared to the same period last year. In July we completed two small propane acquisitions for a total investment of about $25 million; these two acquisitions are not included in our original guidance for the year. We are increasing our adjusted EBITDA target for fiscal 2018 to $105 million for the retail propane segment based on these two additions. As a reminder, we have forecasted this year based on volume estimates using an average of the prior three-year actual results which includes two of the warmest winters in the past 120 years. Weather and the impact it has on heating demand will continue to be the biggest driver of our retail propane segment. And now for the more difficult one, refined products. Refined products lost approximately $8 million this quarter which was a significant blow our expectations for the quarter. Our southeast business which is the legacy TransMontaigne business on the Colonial and plantation pipelines was the driver behind this loss. Colonial lines based average negative $0.025 for the quarter which was lower than our expectations. We estimate that this resulted in about $13 million difference to our original guidance which we do not expect to recover during the remainder of this year and less line space values increased significantly. Additionally, the gasoline inventory values resulted in a negative inventory evaluation adjustment of approximately $19 million in this quarter as the current inventory values decreased more than the increase in value for our hedges which are in the future. We expect this adjustment to move back towards zero through the year based on the timing of the inventory hedges in place. Essentially we recognized the mark-to-market of the inventory and hedges for that inventory throughout the holding period in EBITDA. However, the inventory is marked to a current value and the hedge is marked at the future value on the curve. Current month price moves are more volatile than future periods resulting in the variance in the period and the value of our inventory versus the offsetting hedged position. As we have seen historically, the cumulative adjustment moves towards zero as the hedges are ultimately realized during the fiscal year. This has been included in adjusted EBITDA in a practice utilized by the Company since the acquisition of the TransMontaigne business and is fully explained in the non-GAAP financial measure footnotes. We anticipate that a significant portion of this adjustment will return in the second quarter and we also anticipate improvement in our margins based on our new contracts and improved terminal pricing and our current operating strategy that Mike covered. We've addressed the majority of our earnings volatility related to line space through the re-contracting efforts and other strategies. However, we have also reduced our expectations for the margin contribution from these contracts for the remainder of the year from an average of about $0.04 per gallon to approximately $0.0325 per gallon which includes our fixed price and any remaining variable priced contracts. This isn't approximately $10 million reduction from our original forecast going forward. Besides the southeast business, the remainder of the refined product segment which consists of our mid-continent and rig marketing business, and our ethanol and biodiesel renewable business are expected to perform consistent with our original guidance. While we still have work to do, we do believe the worse is behind us and continue to believe in the long-term value of owning line space on Colonial. We are reducing our fiscal 2018 expectations through this business unit down by $30 million based on first quarter results and current market expectations. Our new guidance target for this entire business segment is now $100 million of adjusted EBITDA. Our corporate cost came in exactly in-line with forecast and prior year at $6.6 million and we continue to expect about $25 million in overhead costs for the entire year. Overall, we generated approximately $39 million of adjusted EBITDA this quarter; total fiscal 2018 adjusted EBITDA is forecasted to be between $475 million and to $500 million. The primary variables of our guidance will be rag [ph] margins for gasoline and diesel, crude prices remaining around current levels and drilling activity remaining stable in our core basins; and obviously, the winter weather and heating demand will have an impact on our results. At this time we expect to distribute $0.39 per unit for the next three quarters or $1.56 per unit annualized. We do not expect to -- we do expect to remain under covered on our distribution for the next quarter and to rebuild coverage in the fiscal third and fourth quarters to approximately 1.2x for this year and continue with a long term target of 1.3x coverage on a trailing 12-month basis going forward. From a growth capital spending standpoint, we have invested about $50 million through June 30 and continue to estimate $150 million to $200 million of growth CapEx for the entire year. CapEx for this quarter include the acquisition of the remaining NGL Solid Solutions business, contributions for the extension of Glass Mountain and additional growth opportunities in the water business primarily focused in the Delaware Basin. As I mentioned earlier, in July we invested about $25 million in two small retail propane opportunities, which we are now including in our full year EBITDA guidance projections. However, we have not modified our growth CapEx expectations for the year. With respect to the balance sheet, we've had to adjust some of our balance sheet management plans. This included amending our debt agreements to allow for a period of increased leverage to the results of the past two quarters. A complete summary of the amendment were included in our 8-K filing in early June as well as in the upcoming 10-Q, but generally speaking, we increase our leverage covenant to 5.5x through December 31, 2017 and lowered our interest coverage to 2.25x over the same period. We do expect to manage within these parameters and expect leverage to decrease when we replace last year's 4Q with this year's results. However, we are actively looking at opportunities to accelerate this deleveraging, whether it be opportunities to enhance EBITDA, reduce indebtedness or monetize certain assets. Our compliance leverage as of June 30 was about 5.2x compared to our amended covenant leverage of 5.5x. We expect leverage to remain elevated through to September 30 quarter and then to reduce by our fiscal year end with a target of 4x or less by that time. Management continues to target compliance leverage of 3.25x or better over the long term. As a reminder, the pro forma adjustments to compliance to EBITDA includes approximately $50 million related to Grand Mesa and about $19 million related to other projects and acquisitions completed during this past quarter. As a reminder and in accordance with our debt agreements, these leverage metrics exclude our working capital facility which is governed by a monthly borrowing base determined by our receivables in inventories. During the quarter, we reduced debt by $118 million and maintain the balance of our acquisition facility at zero as of June 30, while also reducing the outstanding balance on our working capital facility as well. The debt reduction was primarily achieved by the completion of our Class B preferred unit offering was completed in June and raised over $200 million in net proceeds and realized cash flow from working capital primarily collections on receivables from the fourth quarter. I would like to point out that we did not utilize our ATM during the quarter and we do not currently plan to utilize it during the second quarter either. We will continue to focus on reducing debt and doing so with minimal if any dilution to the common unit holders. I would like to reiterate that the Class B preferred units we issued are cumulative perpetual redeemable units - meaning that we must pay the coupon prior to paying distributions to common unit holders, but these units can be held outstanding in the perpetuity. We have an option to redeem them at five years at par and at which time the coupon will convert to a floating rate based on LIBOR, but there is no conversion or put right to the holder other than in a change of control. We view this issuance as non-diluted to the common unit holders as these units are not convertible into common and they do not result in any additional IDRs to the general partner. In summary, we are obviously not immune to market dynamics and we must think in considerable effort to minimize future volatility where possible across each of our businesses. We are attempting [ph] to provide our investors and analysts, as well as the entire market with the best information we have available. We're continuing to focus on our balance sheet and ways to reduce indebtedness and fund growth opportunities without doing in our unit holders or jeopardizing our long-term objectives as we move forward. We remain optimistic about the future of each of our business units for many of the reasons we have discussed today and many we have discussed in the past. We look forward to delivering improved results in the following quarters. Kenzie [ph], we would now like to open up the line for questions.

[Operator Instructions] Your first question comes from the line of T.J. Schultz. Your line is open.

Hi, Mike. This is Rahul, in for T.J. Just had a few questions here in regards to your restructured contracts. I was wondering, do you guys have any leverage - under these contracts, do you still have any leverage to the upside, should line space values increase? And is there a more stable quarterly or annual run rate for the segment with these contracts in place now?

Answer to the first one is yes, do we share in the upside or the positive, but we do not go negative. And what that will do is make our margins more consistent, but we're still subject to this volatility due to our hedging program and the relationship of the prompt [ph] month price change to the out-month price.

Okay. For your 2018 guidance, I know you guys have previously mentioned that assume the sub-normal winter for retail propane. What kind of an impact relative to guidance would there be, should there be in normal winter?

Normal winter would be about 10% higher. Colder than normal winter would be 15% to 20%.

Okay.

And a warmer-than-normal winter would maybe be 10% lower if that. I think last year is a comparable number for the downside.

We did take an average over the last three years. That was 5% or 6% warmer on average. It would have to be warmer than that to ever lower number than what the guidance were providing.

Okay. And then last question, are there any restrictions from the banks after the recent amendments on paying your distribution on lower coverage level? I just want to get your comfort level with the current payout.

The only restriction on distribution is that we cannot increase the distribution if our leverage is over 4.25x where our interest coverage is under 3x, but there are no restrictions or limitations on the current distribution level.

All right. Sounds good. Thank you, guys.

Thank you.

Your next question comes from the line of Shneur Gershuni. Your line is open.

Hi. Good morning, guys.

Hey, Shneur.

Starting I guess with the guidance, right now the guidance is now 475 versus to 500 and it was 500 to 525, which is kind of basically a $25 million down draft. But I think in your prepared remarks, Mike, you have said that you thought that you were tracking this quarter about $10 million below expectations. Obviously that would sound like it's a bigger delta in terms of tracking error. Where do you think the difference is, where do you think you're going to be able to make up the difference versus where you're tracking versus original plan?

I'll start. Shneur, one of the things and in my comments, I mentioned because of the recontracting on Colonial, we estimate that that's about $10 million impact to the rest of this year, so that's not an impact that was realized earning this quarter, but it is the impact that we're forecasting based on current line space values. That number could change if line space were to move positive. As Mike mentioned, we do get some of the uptick in mind space values, we're capped to zero on the down side. That's $10 million of the difference - $13 million is what we believe has been. We've essentially not be made up based on the impact from the first quarter.

Great. But I guess my point is that you're tracking $10 million for the year below on your first quarter. Right? So it's $40 million annualized, but the guidance only moved down $25 million?

Got you. The $10 million, it was lost from the first quarter, does not annualize. We kind of debated what do we do for guidance? Do we just drop it to 500? What do we do? So we decided to just be a little more conservative and go to the 475 to 500.

Got it. Okay. And with respect to propane expectations, you're assuming that the average heating degree days for the last two winters is now normal for your guidance?

No. We took the last three and averaged it. I think most in these three does some kind of normalization. The last two winters have been much warmer than normal, so they keep going back to normal seems like you're banging your head against the wall. So we just took an average of the last three years. I think three years ago, it may have been 4% or 5% colder than normal. The last couple have been 10% to 15% warmer. If you had them together divided by three, that's why I came up with 5% or 6%. Our guidance is based on 5% or 6% warmer than normal.

Okay, got it. Last fiscal year, you had some propane inventory liquidation issues. What's being done a, to mitigate that and; b, if prices zoom up, does that potentially present that risk again if price has moved up, but then all of a sudden you don't get the weather that you're thinking in February? What's being done basically to avoid being long inventory at the wrong times?

That was a function of the weather and supply situation in the New England area, which a lot of the contracts are based on a Bellevue [ph] Index. So you are correct, we have a requirement in our contracts that the counter party has to take 90% of the contract, so we are only committing ourselves to 90% of the contract volumes. We are also doing some things with exchanges, so that we can short ourselves in that February-March time frame. So if it does turn out to be warmer than normal, we will not be stuck with the length that we had last year. The other unknown, which is going to be interesting to all of us is the MEE2 [ph] pipeline, if that's on stream in service and moving liquids out of the New England area - will that really get rid of the excess supply? Or be effectively a hub just like Conway or Belleview that the excess supply can go into that pipeline and be exported. That was a bit major, I guess, an impact as what was going on the blind space, but we have changed our strategy up there in New England area, so it does not happen again.

Okay. Just sort of shifting to line space. You've talked at length about colonial. Can you talk about the plantation? Are we going to have any similar issues there? Do you see that coming and do you have space on any other systems that we should be watching as well, too?

We do not have space on any other systems. Some of the other core systems might be Mid-Con, NuStar, Explorer, Magellan, but those are not on allocation and there's not a line space issue. It's limited to the southeast. We also have some line space on plantation and we've not experienced...

It's been essentially flat.

Flat.

Yes. It's been the Colonial line space.

Okay. Final question on water segment that's doing all right. There has been some talk about completion crew shortages in the Permian and some of the higher areas and so forth. Would that have an impact on your water expectations at all?

That at the bottleneck at the moment is getting permits approved. We have at least 14 or 15 permits out there. It's taking six to nine months to get approval. That's why I say we're fortunate because we have getting this year a million and-a-half barrels of capacity through all the basins and we're running maybe 500,000 barrels a day. So we've got plenty of space. Where it's getting tight is in the Delaware. That's where the majority of our permits are. We haven't seen oil-filled service or completion rig, completion crew issues yet. So the answer is we don't think so.

All right. Perfect. Much appreciate. Thank you for the color.

Your next question comes from the line of Gabriel Moreen. Your line is open.

Hi. Good morning.

Hi, Gabe.

Hi. Just a couple of questions on Colonial fundamentals. I know there's a refinery down at Mexico, exports has still been pretty healthy up the Gulf Coast and that there's a refinery down in the East Coast, too, which also means that exports from Europe to New York harbor, less than a bit as well. Can you talk about the dynamics a little bit and whether they're having any impact at least in the near term on line space before the market [indiscernible]?

Yes, we have news, tell me when you've had enough. Things were very zeroed in on the what I call more of the macro stuff. I think it was a Rotterdam refinery that went down earlier in the week or the weekend, so that means less gasoline produced. That should mean less exports from Europe. We were seeing a decline in the exports from Europe into the harbor. They were heading down to the South Central America. So don't know that that's going to have an impact. The greater impact on the harbor is just continuing to see the inventory draws there. With line 1, Colonial have no longer an allocation. That means there's less making it into the harbor. As all the customers along the line are still taking what they did last year or more; so we're seeing less coming from the gulf -- we believe going from the gulf up to the harbor, and with the draws we're saying that we should get tighter. I think our bob [ph] got pretty tightly heard, earlier this week or last week. The refinery in Mexico that went down was on the West Coast. Those refineries in total have been running about 60%. I think Pemex [ph] publishes numbers once a month. So last report was 60%. Last winter, they were only running at 50% and that's when we saw the exports to Mexico jump from maybe 0.5 million barrels a day to 1 million barrels. They're back down now we think in the 500,000 to 600,000 barrel a day range. The refinery on the West Coast impacted our West Coast refiners, so much of the short fall they had in that refinery came out of the West Coast, not the Gulf. And I believe a bit of that, because I think it was something of a refiner, it was at 400,000 barrels a day. We think a lot of that was exported. So that is not been a factor in the Gulf Coast. The trend seems to be drawing down in the harbor, we're not seeing any more imports up there and steady to slight build in the gulf coast and we're not seeing any excess exports out of the Gulf.

Thanks, Mike. That was helpful. Then just turning to asset sales and the potential there. Can you maybe talk about which segment you're looking for? Are these sizable things or core things like Grand Mesa? If you can speak to that?

Sure. The Grand Mesa, I cannot imagine ever being on the table. So not in Grand Mesa. There are still an awful lot of upside on that pipe. We're actually looking at multiple segments. I think it takes something in the $200 million range to make the difference we want to make. So obviously you need a double-digit multiple to bring the leverage down significantly. We're looking at the moment and I think four of our segments, we have identified some assets and we are pursuing those opportunities. Yes. It's not gambling something on one asset. No. We're trying to be thoughtful about it, we don't want to unbalance our five segments, we don't want to eliminate one segment entirely, so we've identified those assets that have I think a lot of interest from other companies that we would not be giving up future growth.

Okay. Thanks, Mike. And then just in terms of hedging [indiscernible] oil at water solutions, I assume you want to be more than 25-30. It depends? Is it just a matter of washing the curve?

Yes. This is one, Trey could probably talk about a long time like I could about refined products. But it doesn't make sense. We think just hedge 100% all at one time. So we're going to layer into this. I think our budget was of around for the year -- it was 2,600 barrels a day.

Barrels, yes.

Yes. We're going to be higher than that because of the increased water that we're receiving. So let's say it's 3,000 a day, we hedged 25% of that. I know we had some orders in for between $50 and $51, but did not get transacted, but that would be a level for the next 25% and that we'd be at least 50% hedged. Trey?

And the idea, Gabe, is to step into the hedges over time. We don't see that there's any benefit really to hedging at $40. At $50 we are stepping into some hedges. Again, that's in-line with our budget. We can hedge up to 90% of our expected volumes for one year, 50% for two years and 25% for three years out. So we've started that program here recently and we're layering in positions at this time.

We're probably competing every other upstream company to the United States for hedges.

Which is probably why there's a bit of a cap at $50.

Yes.

At least you only have a couple of thousand barrels to do [indiscernible].

Exactly.

Right.

All right. Thanks, guys.

Your next question comes from the line of Lim Shen [ph]. Your line is open.

Hi. This is Matt Niblack. Thanks for the walk-through on what happened in the quarter. I just wanted to understand on the refined products guidance for the year. Are you assuming anything above your sort of minimum contracted rates for value of line space in that spread?

We are assuming that line space is essentially zero at this point in time. As Mike mentioned, we are doing things contractually and physically to make line space zero, so we put a floor on our contracts. Any contracts that are exposed to line space, we are buying the line space and getting paid with that differential. So that essentially negates the negative. We do have some potential to the upside. Our upside forecast for the rest of this year is between a penny and two pennies - all of that really in the third and fourth quarters. So zero in the second quarter and a penny each quarter thereafter.

And if that penny or two doesn't materialize, how much downside is there to the guidance?

The penny is only under discretionary.

I'm just getting my calculator out here, which is my head. We have bought that 100,000, so 20,000 a day x 42 x a penny x 180 days, 1.5 million.

1.5 million? The downside to your refined products, guidance for the balance of the year is only 1.5 million if line space never recovers?

Based on line space. Yes.

Based on line space. Right.

Are there risks or downsides to that guidance or is it pretty solid now to your contract structure?

There are still some variability in that business. We do some blending, we've got storage, inventory values can move a little bit. We try to be very conservative with guidance and continue to be and we're updating it real time. I think we've eliminated the vast majority, the volatility, the amount tied to line space has been essentially eliminated. Volume will also be a driver. We've seen robust volume and we expect that as demand continues to increase throughout the year. But those are the variable components, I think. Margins that we ultimately realize at the racks and the volume on those margins is what the driver is going to be. The guidance they gave was $3.25 per gallon, which is down from just over $0.05 last year and force them so it was in our original guidance.

So I put it another way is; we think we whacked the heck out of refined products, we've taken our line space to zero in the discretionary and $0.01 for the second and third quarter, we've reduced margins from plus $0.05 to $0.0325; so it's hard to imagine how it gets any worse. We do have some upsides on the renewable side that would be significant, so we think we've been pretty damn conservative and we have some upside.

Great, thank you.

[Operator Instructions] Your next question comes from the line of Jason Menda [ph].

Thanks for taking the questions. Just -- can you give us the size -- I don't think you have on the propane businesses acquired and how much of that is included in the 105 estimate for the year now?

Yes, too small -- small acquisitions. The cumulative was $25 million and $5 million of EBITDA is what we added to our guidance. And we're going to have those -- yes, we'll have those businesses through the heating season since we did not have them during the first quarter which is typically a breakeven or zero period.

Got it, great. So only five of the 105 is related to the acquired businesses?

Correct.

And then separately on the covenants [ph], obviously we had the revolver amendments; anything that can't be done and -- so how can you layout what kind of headroom you have on the covenants in the private placement note? And if there is any ability to get any release there?

Those are consistent with -- those have been in a minute and are consistent with the credit facility.

Great, thanks for your help.

Your next question comes from the line of Simon Curman [ph], your line is open.

Hi, good morning. You had mentioned potentially monetizing assets to help deliver; couple of questions, are they going to be size-wise similar to propane acquisitions or would they be more needle movers with regards to delivering? And also do you have any limitations or restrictions on potash use of proceeds as to whether we need to pay down any of your specifics that off borrowings versus you can just do it for any -- you can use it for any purpose. Thanks.

I'll handle the first one. There is no reason to do anything unless it is a needle mover. So yes, it's a needle mover we wouldn't mess, really mess around with anything in that $25 million range.

And on the second question, there is really not any requirements; again, our acquisition facility has paid zero. We would target our -- probably our most expensive debt to repay but there is no real requirements on what we have to do with those proceeds.

Thank you.

I am showing no further questions at this time. I would now like to turn the call back to the Company.

All right, well, so guys thank you very much. We will expect to have better news in the second quarter. Thanks.

Thank you.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day. You may all disconnect.