Magellan Midstream Partners, L.P.
Q2 2020 Earnings Call Transcript

Published: 30 Jul 2020

[Operator:]

Greetings, everyone, and welcome to the Magellan Midstream Partners Second Quarter Earnings Call. During the presentation, all participants will be in listen-only mode. Afterwards, we’ll conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded today Thursday, July 30, 2020. I would now like to turn the call over to Mike Mears, Chief Executive Officer. Please go ahead.

[Mike Mears:]

Hello, and thank you for joining us today to discuss Magellan’s second quarter financial results as well as our latest outlook for the full year. Before we get started, I must remind you that management will be making forward-looking statements as defined by the SEC. Such statements are based on our current judgments regarding the factors that could impact the future performance of Magellan but actual outcomes could be materially different. You should review the risk factors and other information discussed in our filings with the SEC and form your own opinions about Magellan’s future performance. As you know the year 2020 has been challenging, not only for our industry, but the nation as a whole. Magellan has continued to competently manage through the current challenges while remaining focused on executing our long-term strategy to maximize value for our investors. We continue to focus on the health and safety of our employees as we operate through the pandemic. And I’m happy to report that we have had no material COVID related disruptions to date, and all of our facilities are operating normally. As you probably saw this morning, our second quarter results exceeded our expectations due to a number of favorable items, including additional product overages, higher than expected commodity prices and lower operating expenses. Our overall refined products and crude oil pipeline shipments during the quarter trended very similar to the updated projections on our first quarter call. Our CFO, Jeff Holman, will now review our second quarter financial results versus the year ago period in more detail. Then I’ll be back to discuss our latest outlook for 2020 before opening the call for your questions.

[Jeff Holman:]

Thanks, Mike. As usual, I will be making references to certain non-GAAP financial metrics, including operating margin and distributable cash flow, or DCF. We have included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures. Earlier this morning, we reported second quarter net income of $133.8 million or $0.59 per unit on a diluted basis compared to $253.7 million or $1.11 per unit in second quarter of 2019. Excluding the impact of mark-to-market activity in the current quarter, adjusted diluted earnings per unit was $0.65, which exceeded the expected range of between $0.35 and $0.50, which we provided with our first quarter earnings release. Distributable cash flow for the quarter was $209.5 million, $105.3 million lower than the $314.8 million reported in second quarter 2019, primarily due to a combination of lower refined products transportation volumes, lower crude oil spot shipments, and lower commodity margins in the current quarter. I’ll know, as a reminder that following the sale of three marine terminals in the first quarter of this year, we now report our businesses in just two segments

[Mike Mears:]

Thanks, Jeff. As the year progresses, we have updated our DCF forecast for 2020 to a range of $1 billion to $1.05 billion. We believe a range of estimates continues to be appropriate at this time – as well as potential volatility in commodity prices. The midpoint of our DCF range includes two key assumptions worth pointing out, with all other items remaining materially, similar to our previous estimates. First, we now expect refined products to manage recover more slowly from the pandemic previously said. As you may recall, our previous forecast for the second half of 2020 assumed that gasoline demand would return to historical levels. Total distillate demand combining both the impacts of the COVID economic shutdowns and reductions in drilling activity would be down about 6% and jet fuel would be down 25%. As a reminder that previous forecast corresponded to the low end of the DCF range. Our new assumptions now correspond to the midpoint of the range rather than the low end of the range. Our new assumptions project average base volume for the second half of the year to be down 6% for gasoline, 12% for distillate and 40% for aviation fuel as compared to the second half of 2019. For simplicity, we have now combined the projected impact on distillate demand from both pandemic related economic restrictions and the lower volume attributable to reduce drilling. As you can see, we have reduced our demand projections for the second half of the year to more closely align with the current environment and raise the confidence level of the associated DCF expectation for these projections. Including the contribution from recent expansion projects, such as our expanded Texas pipeline capabilities, we expect total refined products volumes during the remainder of the year to be essentially flat with the same period in 2019. These estimates are based on a combination of the latest trends on our pipeline system, as well as industry and customer feedback on their volume expectations. Obviously, these estimates are based on predictions of a very dynamic environment. To the extent axles are different than we’ve forecasted, the DCF sensitivity for each 10% change per month in volume is approximately $4.5 million for gasoline, $3.5 million for distillate and $500,000 for aviation fuel based on the product mix, refined products that we transport. The second key assumption for the midpoint is favorable compared to our previous guidance. And that relates to a higher commodity price environment than a quarter ago. As a result of the improved spread between the price of gasoline and butane, we now expect to realize profits from our gas liquids blending activities in the back half of the year with nearly 75% expected fall blending activity now hedged. Based on hedges already in place, plus forward curve for the remaining volume, we expect an average $0.30 per gallon margin on gas liquid blending during the second half of the year. I would also like to point out that the primary reason we have lowered the high end of forecast is because of the significant amount of hedging that we have implemented for the second half of the year, which remove some of the potential for further upside if commodity prices improve, but also remove a considerable amount of risk from our forecast. As previously indicated, Magellan intends to maintain our quarterly cash distribution at the current level for the remainder of 2020. Based on our new DCF forecast range, we expect to generate $75 million to $125 million of excess cash, resulting in distribution coverage of approximately 1.1 to 1.14 times for the year. Considering all of the volatility, the 2020 is offered so far, we believe these solid metrics reinforce the message Magellan stable and resilient business model. Moving to expansion capital, I’m pleased to confirm that our West Texas refined products, pipeline expansion was successfully placed into service on July 1 and that our new Midland terminal became operational this week. This $500 million project will increase capacity into the Dallas, Midland Odessa, El Paso and Mexico markets, and a supported by long-term commitments from solid investment grade counterparties. In total, we expect to spend $400 million during 2020 on expansion capital was 60% already spent to the first half of the year. We were also recently launched a number of small, low risks bolt-on projects resulting in projected expansion capital spending of $40 million during 2021. Magellan remains focused on delivering long-term value for investors and we believe our historical approach to discipline capital management continue to serve as well as opportunities present themselves going forward. Operator, that now concludes our prepared comments. So we’re not ready for questions.

[Operator:]

And thank you very much. [Operator Instructions] And our first question comes from the line of Theresa Chen with Barclays Bank. Please go ahead.

[Theresa Chen:]

Good afternoon and thank you for taking my questions. Mike, I first wanted to just clarify your comment about lowering the high end of the guidance range, because you had hedged out some of your activities. What did the hedging related to – are you referring to your marketing business or is it the butane blending hedges that you’re talking about? Any clarity there, if you could.

[Mike Mears:]

All of our hedging is around our butane blending. Our marketing affiliate has back to back agreements that lock in a margin. So we’re not referring to that. What we’re referring to specifically is the butane blending. And just to clarify more on that range on the DCF forecast, back at the beginning of the first quarter, we provided that range based on in part due to the potential uplift in commodity prices before the end of the year. Now that we’ve locked in a significant portion of the blending margin, a lot of that upside, for example, if the price of crude goes to $45, we can’t obtain. So that’s the primary reason why we lower the upside of the range.

[Theresa Chen:]

Got it. And I believe the previous guidance did not include any contributions from the butane blending business for the fall. Just to simplify things since they are several moving pieces in the guidance change, how much dollars EBITDA or DCF are you expecting for fall butane blending in 2020 that previously was not in the guidance range?

[Jeff Holman:]

I don’t have that number in front of me. I have some folks in the room looking for it, if they can find it in time, I’ll let you know. But I think it’s fair to say, overall, with regards to our forecast range, you can almost view the increase in what we’re going to capture on blending that we weren’t forecasting before is being offset by now projected softer refined product recovery. But I do have the number to answer your question. It’s about $20 million.

[Theresa Chen:]

Great, thank you. And on that point, Mike, just in terms of the lower outlook on refined product demand. So just to get a little bit more granular on – your perspective on this and how you’re thinking about it. Is this because of the resurgence in cases recently? Or is it something more structural as you observe consumer behavior changes, just as we think beyond 2020 and into 2021?

[Mike Mears:]

Well, that projecting future refined product demand is more of an art than it is a science. I can tell you that one of the primary drivers is what we’re actually seeing today. And the numbers that we have quoted for the remainder of the year are not that much different than what we’re seeing in July. So we’re really not projecting a huge improvement. That’s probably not true in gasoline. We’re projecting maybe slight improvement through the second half of the year on gasoline. But diesel demand right now is kind of in the range of the numbers we’re quoting, jet fuel demand on our system in July is only down about 40%. So that’s consistent with our projection for the rest of the year. And so then to the second part of your question, just given the pause and reopening and the continued uncertainty on the surgeon cases and the timing of that plateauing or peaking and dropping back down. We have not really built in a lot of improvement, again, except with a little bit with regards to gasoline on what we’re actually seeing right now.

[Theresa Chen:]

Understood. And lastly, I just want to ask about the FERC index review going on currently that we’re going to get a new escalator middle of next year. So I guess coupled with PPI finished goods trucking to be negative this year and the escalator starting point of 0.09%. Do you have a view on what that final outcome for the escalator could be, especially, given your role in the AOPL?

[Mike Mears:]

Well, my – I can’t predict with a 100% accuracy what the answer’s going to be at the end of the process. My sense is that there’s a probability that we’ll able to achieve and add or that’s a little bit better than what the FERC has proposed. I don’t know, I think it’s a stretch to say that we’ll see anything materially better than that. So that’s probably in the range, when I say in the range, we’ll have a half a percentage point or so, what it’s probably going to be. And again, I just want to clarify that to me, speculating that’s based on any inside knowledge on anything. And so that’s where we – that’s where I kind of view it’s going to be. So if you couple that with what PPI might likely be at the end of this year that doesn’t add up to a very large index adjustment for 2021. So with regards to us specifically, we continue to evaluate alternative rate making options, if we have to look to alternatives and specifically, if we don’t believe that the index is actually covering our costs that we’re going to make sure we’ve looked at all our available options.

[Theresa Chen:]

Thank you very much.

[Mike Mears:]

Thank you.

[Operator:]

And our next question is from the line of Gabe Moreen with Mizuho. Please go ahead.

[Gabe Moreen:]

Hey, good afternoon, Mike. Can I just follow-up on Theresa’s – the answer to Theresa’s last question there and looking at all available option. Is there anything besides going into per rate cases that are a rate case that you’d think about doing?

[Mike Mears:]

Well, that’s the most obvious solution. It’s probably the most – not the most desirable solution. I don’t want to go into a lot of details as to what else we’re looking at, but if you recall, in early May, the commission did put out a notice that encouraged pipeline operators, if they needed to propose creative rate making solutions to address the unusual circumstances that are occurring in 2020. So we’re evaluating what creative mechanisms might make sense and be in compliance with the Interstate Commerce Act. We haven’t made any decisions on anything. And again, a cost of service filing is an option. If none of the others are available. I don’t want anyone to read into that, that we’re planning to do a cost to service filing next year, because it’s all going to be data driven. And as we go into next year and we look at what index is going to be, and we look at what our actual costs have been and what our actual revenue are and interacts with cost of service calculations. We’re going to see how much gap there is, make a determination as to whether we need to make a pilot or not.

[Gabe Moreen:]

Right. It sounds like you need to get some data under your belt as opposed to doing a foreword test here or something like that. But it’s been awhile since the rate is fine to make sure. If I can ask maybe about distillate demand and it seems like maybe there’s been a pullback in distillate demand. That’s been a little more pronounced. I think he would also broken out the components of distillate demand around drilling activity. And then just broader distillate demand maybe you could – demand that you can speak to those components and what’s embedded in the guidance here.

[Mike Mears:]

Well, certainly we’ve seen a decline in drilling distillate demand. That’s been a significant items that’s reduced the year-over-year performance. I think the other one that’s stood out to us is railroad demand that has been soft. But beyond that agricultural demand and trucking demand from what we can sell are down, but not to the same magnitude as the first two items I’ve mentioned.

[Gabe Moreen:]

Thanks, Mike. And my last question is just on some of those smaller projects you identify, I think you mentioned the $40 million. Can you talk a little bit more about what kinds of projects those are? How much more might be in the well and whether any of those are actually going to be impacting 2020 results here?

[Mike Mears:]

Well, first of all, none of them were back 2020 results, but the types of things we’re looking at just to give you a couple of examples, we’re looking at additional connectivity to our Houston distribution system from inbound pipes, which should benefit us with more volume on that system. And another example is we’re looking at a initial, I shouldn’t say looking at we’re implementing an initial incremental expansion of our mountain system, which moves up to Denver and the front range to move more product there. As a result of the Cheyenne Refinery closure and we’re looking. So that’s underway, but we’re also evaluating larger expansion opportunities up into that market that we haven’t made a decision on yet.

[Gabe Moreen:]

Thanks, Mike.

[Mike Mears:]

Thank you.

[Operator:]

Thank you. Next question is from the line of Tristan Richardson with SunTrust. Please go ahead.

[Tristan Richardson:]

Hey, good afternoon guys. Just a quick question on the comments you made around a customer that switched from a transportation contract to your marketing affiliate. Could you talk about just generally at a high level, what occurred there or perhaps, what a rationale might be to see that sort of a change?

[Mike Mears:]

Well, I mean, the simple answer is we traded term for rates, that’s what the trade was. We had a longer term contract for a lower rate. And we were interested in doing that given the current margin market. So that’s the simple answer.

[Tristan Richardson:]

And do you see opportunities for more of that across the remaining customer base on long haul?

[Mike Mears:]

We do, but it’s limited. And the margins, of course, when we did that, which was a year ago, the differentials were quite a bit better than what they are today. So doing that kind of trade today is a little harder to do because the margins are so small on the Midland-to-Houston differential. But what we would have to offer as a lower rate to get a longer term may not make sense, but we’re looking at a few things there.

[Tristan Richardson:]

Helpful. And then just one follow-up on the blending items, appreciate the comments around the opportunities you’re seeing in the second half. Just looking backwards a bit at product margin in the segment. Can you talk about what that average blending margin came out to and either the second quarter or the just first half in general?

[Mike Mears:]

If you’ll give the staff in the room a moment to look that up, I can answer it. I don’t have that handy.

[Tristan Richardson:]

No, I appreciate it. Thank you guys very much.

[Mike Mears:]

Hold on just a second. I’m getting that number off. For the first half of the year, it was about $0.60 a gallon.

[Tristan Richardson:]

That’s great. Thank you, Mike.

[Mike Mears:]

Sure.

[Operator:]

And the next question is from Jeremy Tonet with JPMorgan. Please go ahead.

[Jeremy Tonet:]

Hi, good afternoon. I wanted to start off, I guess, revisiting capital allocation philosophy, thoughts on that, looking 2021, the CapEx really falls out of a bunch there and looks like the free cash flow really kind of ticks up. And so it seems like you have a lot of flexibility with regards to the dividend or repurchases or leverage. I’m just wondering if you could update it there on kind of how you see those priority is interplaying.

[Mike Mears:]

Sure. Well, I mean, first of all, we’re not going to made decisions on 2021 now. And we’ll wait, we get into year and see what our capital forecast looks like. And I want to emphasize is nothing’s really changed with regards to what our first choices with regards to spending our free cash flow, and that’s on projects that have good returns. And so that’s we’re continuing to look for those. Obviously, it’s more difficult to find those in this environment. As we just mentioned, we found $40 million worth of opportunities here in the last few months. We may find some more as time goes on. But we intend to be very disciplined as we have in the past with regards to those types of investments, especially in this environment that they really have low risk opportunities to generate returns that are attractive to us. So that’s our first choice. Now, if we cannot find those and we don’t increase our expansion capital budget for 2021. Then, we will definitely look at a unit buybacks or distribution increases. And those decisions will be made really at a point in time in the future when it’s abundant that we need to make that decision that we’ll have that excess cash. And that it’ll really be driven by what the current valuation is on our units and whether we think that’s the best place to put the cash versus distribution.

[Jeremy Tonet:]

Got it. Thanks for that. And then just one last one, if I could. With regards to the industry overall, energy industry is kind of slowing down here, hitting more mature state. What role does Magellan play in that environment where maybe there’s a period of consolidation, or I don’t know if you have any other kind of views as the industry matures a bit here?

[Mike Mears:]

Well, I agree with you. I think we’ve reached a level of maturity in many parts of this business. And M&A consolidation makes sense in that environment. We’re not opposed to it. We actively look at that. And if we can find a combination that makes economic sense and we have a willing counterparty, then we’ll pursue that. So that’s really all I can say with regards to that is, it’s something we’re interested in. It’s something we’ll participate in if the numbers work, and so stay tuned.

[Jeremy Tonet:]

Great. Thanks for that.

[Mike Mears:]

Sure.

[Operator:]

The next question is from the line of Shneur Gershuni with UBS. Please go ahead.

[Shneur Gershuni:]

Hi, good afternoon, everyone. Maybe to start off, I was wondering, if we can go back to the –again just, I don’t want to totally be labor the point here. But if I understood you correctly, you said that there was an expectation for butane blending in the original guidance that you gave, and that was part of the commodity comment. I just wanted to clarify that point.

[Mike Mears:]

No, well, we gave guidance in early May, there was no blending income, or maybe a better way to phrase as an immaterial amount of blending income in the second half of the year.

[Shneur Gershuni:]

Okay. So when I sort of think about the $25 million lowering range, or let’s call it a $12.5 million midpoint lowering. And I think you said before, it’s $18 million to $20 million was for butane blending, should – is – on an apples-to-apples basis, is that the way we should look at the lowering that you’ve lowered the guidance range midpoint by about $30 million when I make those two adjustments?

[Mike Mears:]

I’m not sure, I followed your map, but let me tell you how I would explain it. When we provided the guidance in May or the forecast range in May, I should say, we hadn’t hedged anything in the call. And when we look at the range of possibilities as to where that margin could be, it went from zero to a high end, I can’t recall exactly what the high end is that we assumed in the upper end of our range back in May, but that was driving a substantial portion of that potential upside on that forecast range. And so – and I don’t know the number, but let’s just assume that was a $45 a barrel crude price would have corresponded to the high end of that range. Such that if we hadn’t hedged anything or the prices moved to $45 and we’d locked everything in a $45, we could have hit the high end of the range if nothing else changed. Well, what’s happened is we got into the high-30s, the margins were available. So we started to hedge the blending and locking in those profits. And so as I’ve said, we’ve locked in about $20 million worth of profits. Well, once we’ve done that, we’ve taken away the upside if the price goes to $45 or higher. We’ve taken away that upside. And so that’s what we’ve essentially taken out of, well, that’s a large portion of why we’ve lowered the guidance range is, because that upside is now no longer available. But the flip side of that is we’ve now locked in 75% of what we were able to capture. So we have a lot more confidence on the range that that we’ve provided now.

[Shneur Gershuni:]

And sort of paraphrase, basically the bottom end of the range, you weren’t expecting to basically get any butane blending and then the high end of range, there should have been an opportunity to enable to do that. Now that you’ve locked that in, we kind of know what that is. So the bottom end in theory is more secure, is it – did I paraphrase that correctly?

[Mike Mears:]

I think that’s right. And maybe another way to phrase is the midpoints more likely.

[Shneur Gershuni:]

Okay, perfect. Sorry for belaboring that. Maybe to pivot a little bit to your commentary around the projects that you’re evaluating. I know that your backlog is often $500 million or more. I was just wondering if the ones that you’re evaluating very closely right now, or front burner. What’s the range of capital spend on those types of projects?

[Mike Mears:]

Well, we continue for instance to work on potential expansions of our Pasadena terminal. And we’re actively doing that as we speak. Magellan’s portion of that capital, if we were to do that, could be in the $100 million range or so, or looking in a number of potential expansions to Denver, which could be in that similar types of range. So there’s – I mean, there’s a number of viable or what appear to be viable projects at this time. They could get us the $200 million or $300 million worth of capital next year. But those projects aren’t done yet, and there’s a chance they won’t get done. That’s why I was cautious on the answering the previous question as to whether we’re going to be looking at buybacks or increased distribution. It’s all relative to how successful we are on some of these other opportunities, but I also want to reiterate that we are not pursuing growth projects simply for the benefit of growth. And they need to be solid, secure, committed projects from credit worthy counterparties before we would proceed. And in this environment, those are more difficult to obtain. So we’ll just see how this plays out.

[Shneur Gershuni:]

That makes perfect sense. And I actually that was where your concluding part was where my head was headed. And so when we think about dollars available for unit buybacks, if let’s say you sanctioned $200 million worth of new projects, the way you would position it to the Board would dollars available for buybacks have to be after you’ve funded the full CapEx with internally generated cash flows, so differently dollars would be available free cash flows after full CapEx and dividends. Is that kind of the way to think about of what could potentially be available for buybacks?

[Mike Mears:]

I think generally speaking that’s the right way to look at it. I mean you can take extreme cases, just leverage level gets so low that it just doesn’t make sense to maintain leverage levels say at three times or below three times. Then we may change our view on that, but that’s the way you just characterizes our current view.

[Shneur Gershuni:]

Perfect, all right. Well, thank you very much, guys. Really appreciate the color today.

[Mike Mears:]

Thank you.

[Operator:]

And our next question is from Derek Walker of Bank of America. Please go ahead.

[Derek Walker:]

Hi, good afternoon, everyone. A quick clarification question on the guidance on the assigned products based volumes. Like I believe you, you alluded to some assumptions that gasoline is affecting improve in the second half. Are you expecting that to normalize sort of by year end based on kind of what you’re seeing from today. I just wanted to make sure understood sort of what that ramp expectations.

[Mike Mears:]

Well, I mean just to give you a sense of how we came up with those numbers again, I kind of talked about this a little bit before. For July, we’re kind of – on gasoline demand, we’re kind of in the range of 8% to 10% down for July. In for distillate, we’re kind of in that 12% range down for distillate and on jet fuel down 40%. So first of all, with regards to distillate and jet fuel, I mean, July is consistent with the rest of the year expectation in our forecast. So we’re not really projecting any considerable improvement in when I say that I’m talking material improvement in this literature yet through the rest of the year, but we’re also not projecting it go down again, which could happen. I don’t want to just portray the upside. I mean if we have a resurgence in cases and we have more backups on the reopenings, then it –there’s downside to that too. A gasoline, like I said, we’re in the 8% to 10% range down, we’re projecting 6% for the rest of the year on average, just based on the trends has been improving through the month of July. And so that’s really kind of the basis for our projections there. It’s not, I don’t know that it’s any more complicated than that. We’re not really trying to project anything significantly changing either positively or negatively through the rest of the year where the potential of either one of those things exists. As that rolls into 2021, and also we haven’t really thought about 2021 too much. It’s too hard to predict the rest of this year, much less worry about 2021 at this point.

[Derek Walker:]

I appreciate the color there. Maybe just a quick follow-up on just some maybe optimization or cost savings initiatives. I think you have some of that baked into your guidance. Has there been any incremental updates on that front? Any other cost saving opportunities relative to what you previously provided?

[Mike Mears:]

There’s really nothing new to speak of this material to affect 2020, but we have been making a lot of progress on efficiencies that will impact or improve in 2021 and beyond. So now we’re going to start seeing the real benefit of those lot of things we’re doing.

[Derek Walker:]

Okay. That’s helpful. Thank you.

[Mike Mears:]

Thanks.

[Operator:]

And gentlemen, those are all the questions we have at this time. I’ll turn the call back over to you, Mr. Mears for any closing comments.

[Mike Mears:]

All right. Well, thank you for your time today, and we appreciate all your support at Magellan. Have a good afternoon.

[Operator:]

And that does conclude our conference call for today. Everyone, have a great rest of your day, and you may disconnect your line.