Earnings Transcript for MMP - Q1 Fiscal Year 2022

Operator: Greetings, and welcome to the Magellan Midstream Partners First Quarter '22 Earnings Call. . As a reminder, this conference is being recorded, Thursday, May 5, 2022. I would now like to turn the conference over to the President and Chief Executive Officer, Aaron Milford. Please go ahead.

Aaron Milford: Hello, and thank you for joining us today to discuss Magellan's first quarter financial results. Before getting started, we must remind you that management will be making forward-looking statements as defined by the Securities and Exchange Commission. 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. Since this is my first opportunity to speak publicly as Magellan's CEO, I would like to express how honored I am to lead this exceptional organization. As you know, I've spent my entire career with the company, including serving as Chief Financial Officer and most recently, as Chief Operating Officer. So even though I'm new to the CEO role, I've been around for a while. And I intend to remain focused on the overarching goal of maximizing long-term investor value while retaining our strong financial position and consistent disciplined approach that Magellan is known for. As reviewed at our recent Analyst Day, no matter which industry projections you consider, we expect our services to be needed for a very long time, and our company is poised to serve our nation's critical energy needs for decades to come. We remain committed to doing things the right way, ensuring that we are operating in a safe and efficient manner at all times. I'm confident in Magellan's future and our ability to create long-term value for our investors. With that, I'll turn the call over to our CFO, Jeff Holman, to briefly review our first quarter financial results. Then I'll be back to discuss our latest outlook for the year as well as the status of a few of our expansion projects before answering your questions.

Jeffrey Holman: Thanks, Aaron. First, let me mention that, as usual, I'll be making references to certain non-GAAP financial metrics, including operating margin, distributable cash flow, or DCF, and free cash flow. And we've included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures. Earlier this morning, we reported first quarter net income of $166 million compared to $221 million in the first quarter of 2021. At a high level, the year-over-year decline primarily resulted from mark-to-market adjustments on commodity hedges in the current period as well as from the favorable impact of winter storms on our 2021 results. Adjusted earnings per unit for the quarter, which excludes the impact of mark-to-market adjustments, was $1.10, exceeding our guidance for the quarter of $1.02 primarily due to the impact of higher commodity prices and our tender revenue and product gains as well as higher-than-expected refined product shipments. DCF for the quarter of $265 million was $11 million lower than last year primarily due to the favorable impact on the prior year results of the 2021 winter storms just mentioned. As a reminder, we estimated a favorable impact of about $25 million in those storms last year. Free cash flow for the quarter was $240 million, resulting in free cash flow after distributions of about $19 million. A detailed description of quarter-over-quarter variances is available in the earnings release we issued this morning. So as usual, I'll just touch on a few highlights of the quarterly results. Starting with our refined products segment. Operating margin of $235 million was approximately 10% lower than the '21 period mainly due to the mark-to-market adjustments I already mentioned. Our fee-based refined products business actually increased between periods. As we've seen throughout the past year, we continue to benefit from overall demand recovery as life has gotten more and more back to normal, along with additional contributions from our Texas expansion projects. Overall, we saw an 11% increase in total refined transportation volumes relative to the prior year period. Average transportation rates were slightly lower as a higher proportion of short-haul shipments, which move at a lower tariff, more than offset midyear 2021 tariff increases. As we've noted before, we expect this trend to continue throughout the year mainly due to the final ramp of commitments on our East Houston-to-Hearne project to move at a shorter distance and at a lower rate than our average shipment. Operating expenses for the refined products segment decreased slightly between periods, a benefit from more favorable product overages, which reduced operating expenses, more than offset other expense increases we experienced this quarter, including higher power costs, which were higher primarily due to the benefit in the prior year from gains on power hedges, again in connection with the winter storms I already mentioned. Equity earnings decreased due to the sale of a portion of our interest in our Pasadena joint venture. You'll recall that, that sale occurred in April of last year. So this should be the last time we need to mention this variance. Product margin, the largest variance for the quarter, decreased between periods. As already noted, this was due to unrealized losses on our hedging activities in the current period as a result of the recent increase in commodity prices versus unrealized gains in the prior year. With respect to our gas liquids blending sales, our realized margins actually increased year-over-year to about $0.40 per gallon versus closer to $0.30 per gallon in the prior year period. Turning to our crude oil business. First quarter operating margin was approximately $104 million, down 5% from the same period last year. Longhorn volumes averaged about 235,000 barrels per day during both periods, while we benefited from the higher average rate during the recent quarter due to the mix of customer volumes moved during the period. On our Houston distribution system, lower tariff shipments were offset by higher terminal throughput fees as more customers elected to use the simplified pricing structure for our services within the Houston area. We've seen growing customer interest in such simplified pricing arrangements, with the result that even though we have added connections to the HDS and the volume of fiscal barrels we moved has increased, the resulting incremental revenues are showing up as terminal throughput fees rather than as transportation revenues that were reflected in our transportation statistics. So to be clear, while this change impacts our reported volumes, such that our HDS volumes for the year will be different from our original guidance, this change really just reflects a change in which bucket the related revenue falls in. Looking briefly at expenses, although operating expenses for the crude oil segment declined only slightly, I'll note that the '21 period also benefited from the winter storm-related power hedge gains already mentioned. Lower integrity spending and lower pipeline rental costs more than offset the relatively higher power expense in the current period. Moving on to our crude oil joint ventures. BridgeTex volumes were approximately 285,000 barrels per day in the first quarter of '22, down from nearly 300,000 barrels per day in 2021 partially due to the timing of when our committed shippers have elected to move volumes under their commitments, while Saddlehorn volumes increased to more than 220,000 barrels per day compared to approximately 180,000 barrels per day the year before primarily driven by the ramp-up of new commitments associated with the pipeline's expansion. I did also want to point out that we recognized additional deficiency revenue for both BridgeTex and Double Eagle pipelines during the quarter, which more than offset lower average rates on Saddlehorn, resulting in a slight increase in overall equity earnings for the crude oil segment. It's important to note that although this recognition of the efficiency of revenue results in higher equity earnings, associated cash payments were already received from customers in prior periods and our proportionate share of those payments were distributed to us by our joint ventures and recognized by us as DCF at that time. Just a few other items I would like to touch on. First, G&A expense increased $18 million between periods primarily due to higher incentive compensation costs related to the recent retirement of our former CEO, which resulted in an acceleration of the expense associated with his outstanding incentive comp awards. In addition, we also reported higher incentive comp expense overall just due to Magellan's improved financial results. Net interest expense increased slightly during the current quarter primarily due to a higher average debt balance. As of March 31, the face value of our outstanding debt was $5.3 billion, with the weighted average interest rate on that debt of about 4.2%. Our leverage ratio at the end of the quarter was 3.65x for compliance purposes, which incorporates the gain we realized on the sale of part of our interest in Pasadena in 2021. Excluding that gain, leverage would have been a little over 3.8x. And that brings us to the last item I'll touch on today, which is capital allocation. As you've heard us say before, we remain committed to maintaining the financial discipline we are known for while delivering long-term value for our investors through a combination of capital investments, cash distributions and equity repurchases. During the first quarter, we repurchased over 1 million units at an average purchase price of just under $48 for a total spend of $50 million, bringing total repurchases since inception to 17.5 million units for $850 million. As previously stated, we currently expect free cash flow after distributions to generally be used to repurchase our equity. Of course, as we are always careful to note, timing, price and volume of the unit repurchases will depend on a number of factors, including expected expansion capital spending, free cash flow available, balance sheet metrics, legal and regulatory requirements as well as market conditions and the trading price of our equity. In particular, I'll note that we remain committed to our long-standing 4x leverage limit and also, that the timing of the proceeds from the independent terminal sale remains subject to the government review process, which we believe is nearing completion. And with that, I'll turn the call back over to Aaron.

Aaron Milford: Thank you, Jeff. Considering our better-than-expected first quarter results as well as our outlook for the remainder of the year, we have increased our 2022 DCF guidance by $15 million to $1.09 billion. As everyone knows, the commodity pricing environment is higher than originally expected for the year, which has benefited the value of our product overages, as Jeff just noted. One might naturally expect our butane blending margins to also benefit from the increase in commodity prices. However, we're still forecasting an average blending margin of about $0.40 per gallon for the full year. A significant reason for the muted impact of higher prices on our blending business is that we had already hedged margins for most of our spring blending activity before most of the run-up in prices had occurred. In addition, as we discussed a few weeks ago at our Analyst Day, the basis differential for gasoline sold in our Mid-Continent markets has been quite unfavorable recently and has resulted in lower net margins than we had originally expected. Although we utilized futures contracts to hedge most of the product margin exposure related to our liquids blending activity, our ability to hedge Mid-Continent basis differentials efficiently is limited. And so we are generally subject to those differentials at the time we actually sell the blended gasoline, which, of course, means lower net margins when differentials are as unfavorable as they have been lately. For the year, these lower near-term margins are expected to be essentially offset by higher margins for the fall blending season. We have made significant progress locking in fall blending margins at this point, with about 80% of expected fall activity hedged at margins of around $0.50 per gallon. Given the attractive margins currently available, we've also started hedging next spring as well, with about 40% of our spring 2023 activity hedged at margins of about $0.60 per gallon. Of note, these margin estimates assume the basis differential returns to be more in line with historical trends as the year progresses. With our higher overall DCF guidance, we now expect distribution coverage of 1.24x for 2022, which represents more than $200 million of excess cash. Combined with the $435 million of proceeds we expect to receive in the next month or so from the pending sale of our independent terminals, we should have significant cash flow available to create additional value for investors, consistent with our capital allocation priorities. As Jeff previously mentioned, we currently expect free cash flow after distributions to generally be used to repurchase our equity. However, we also continue to pursue low-risk expansion capital projects that meet or exceed our 6x to 8x EBITDA multiple threshold to create future value for our investors. Based on projects already committed, we now expect to spend approximately $70 million in 2022 on expansion capital. This estimate is $20 million higher than last quarter, in part due to the addition of a new investment to further improve connectivity of our Cushing crude oil terminal. We also launched an open season last week for a potential 15,000 barrel per day expansion of our Texas refined products pipeline to El Paso. From El Paso, the gasoline and diesel fuel can be further distributed to New Mexico through our system or continue on to Arizona or Mexico via connections to third-party pipelines that deliver to those important markets. If we end up moving forward with this project, which we have not yet included in our updated spending estimate for the year, we expect the expansion to cost around $25 million and to be completed by mid-2023. This potential opportunity is consistent with the theme of other pipeline expansions currently underway, which have also been designed to fill current supply gaps created by changing market conditions, mainly resulting from recent closures or repurposing of refineries within our asset footprint. Because of the extensive nature of our system, we were able to satisfy market demand by sourcing product from a broad set of origin points, demonstrating the flexibility of our refined product system that can access nearly 50% of our nation's refining capacity. Along those lines, our current refined products pipeline expansion to Albuquerque is expected to start up next week after a short delay related to some additional pump work that needed -- that was needed. In addition, our Kansas to Colorado expansion is progressing and still expected to be in service by the end of the year to help meet demand in the Denver market. That concludes our prepared remarks. Operator, we're ready to open the call for questions.

Operator: . Our first question comes from the line of Praneeth Satish with Wells Fargo.

Praneeth Satish: I guess I just wanted to see if I could get an update on the potential project to reverse Longhorn, I guess, what feedback have you received from customers and shippers so far. And if you do get enough contracts to move forward, but one, when would you expect more information on that, and two, do you anticipate any significant permitting challenges?

Aaron Milford: Starting with the first part of your question, we continue to evaluate the potential to reverse Longhorn. We don't have a significant update for you today as what we really want to see and understand is what does the market need and want. A first step to that, in some respects, is to understand what kind of demand we get for this open season we have out there that we started last week, where we can do the 15,000 barrel-a-day expansion with our current assets without the need to reverse Longhorn. But depending upon the demand, that may or may not bring the Longhorn reversal potential forward. Now to the second part of your question regarding regulatory hurdles, to reverse the line from crude back to refined products, and recall that the line was originally in refined products, we do expect a permitting process that we're going to have to go through. And that's one of the things that we continue to evaluate. So the reversal of Longhorn isn't something that we can just sort of snap our fingers and make happen overnight. It's something that we'll need to evolve. But a first step in that is to really evaluate what's the demand for refined products out West and is it needed.

Praneeth Satish: Got it. And maybe just a follow-up on this, on Longhorn. I mean it sounds like the whole process to convert Longhorn, if you did it, it would take a while. And at the same time, I mean, production is starting to pick up in the Permian. Permian oil could kind of tighten back up in the 2025 time frame. So is it fair to assume that if you did convert Longhorn, you would do it so that you would earn a higher return than if you kept it in crude service and potentially benefited in 2025 from contracting at, say, $1.50 or $1.75?

Aaron Milford: Yes. Certainly, part of the analysis is, Longhorn, it's valuable today in the service that it's in. So if we make the decision to reverse it, it would be along the lines of what you just described. We see more value in reversing it and keeping it in its current service. So you're right, that's part of the overall valuation. And certainly, the -- with Permian production increasing, you're seeing some fundamentals, I think, improve in the Permian Basin for pipeline transportation. That's part of the equation, is evaluating where do we think it's going to be and what creates the most value for us.

Operator: Our next question comes from the line of Theresa Chen with Barclays.

Theresa Chen: I first wanted to ask about the FTC process as far as the Southeast terminal sales go. How is that going? And related to your comments about using excess cash flow towards repurchases, especially once you get the proceeds, can you give us a sense of the pace of repurchases that you plan?

Aaron Milford: Well, Theresa, I'm going to start with your first question. The FTC process has been a long one. It started last year. The good news is, is we're hopeful that we're approaching the end of that process, and it's consistent with -- I mean, all the guidance we gave this year assumed that we owned the independent terminals through the middle part of the year and we seem to be on that track. So we think we're reaching the end of that process, and we're hopeful that we're going to close, as I said, in the next month or so. In terms of the pace of buybacks, the pace is one that -- it will depend. It will depend on where our units are trading. It will depend on what growth capital projects we would come up with. So we don't have sort of a defined pace to tell you, Theresa. It will be x amount over these amount of months. All I would tell you is, obviously, we're going to generate free cash flow just from our operations, and then we're going to have these proceeds on top of it. So we're going to have ample opportunity to make the decisions that we need to make, in terms of buying our units back. But I don't have a prescribed pace for you to think about. All I would suggest is that you consider the amount of proceeds that we have and our ability to buy back units, contingent upon all the caveats that we put around it.

Theresa Chen: Understood. And on the refined products side, clearly, you spend a lot of time going through the various projects and the debottlenecking opportunities and additional capacity westward, including Europe service to Albuquerque, the expansion currently under contemplation, seeking commitments to El Paso by mid-2023 as well as additional capacity towards the Colorado markets. One of your large-cap MLP competitors has similar projects out there, to very similar markets or exact markets. I'm just curious, as you look towards the medium term, do you think that there could be some overcrowding in these spaces, such that the tariff or the commitments could be competed away. How should we think about that?

Aaron Milford: Well, in terms of competing projects, we think our expansions that we have into El Paso, specifically, we're considering those competing projects that are out there as are the folks making commitments to us. So it's a known quantity in terms of what we're each trying to do. We still think there's a lot of demand going west. So we're still very optimistic about getting the commitments that we will need to expand our pipeline. And then if you look at the markets themselves, they don't overlap perfectly. If you put them on a map, they're in slightly different geographic areas. But we're not annoyed of the fact that there's potentially new capacity coming into these markets, which can access all the way up to Western Colorado. So we're taking that into account. We think if you look at the growth that's happening in Colorado overall, if you look at the growth in volume that's occurring in El Paso, Mexico, points further west of that, look at the growth that can occur within the even the Permian, I don't think we're at a point where we're overly worried about too much capacity as we move forward. We still see quite a bit of opportunity out there. But we'll have to see.

Theresa Chen: Got it. And lastly, just as we think about product balances and shifts, and specifically the Gulf Coast, I was wondering, one, are you connected to the Lyondell Houston refinery, and if that eventually shuts down, will that be taking some volumes off of your refined product system. And two, as the Gulf Coast seems to be the incremental supplier of clean products, especially diesel, to international markets that seem to be tighter and tighter given the Russian distillates coming off the market, do you see kind of like a pull away from your system that pipes to the Mid-Con and beyond in favor of exports? How should we think about that?

Aaron Milford: So let's take the first part. We do have a connection to the Lyondell refinery. But what I would say is we don't have a lot of exposure. So I wouldn't draw any conclusions from if that refinery shuts down, that, that should mean something negative for our assets because frankly, we're connected to a bunch of other refineries and the demand that we have at the end of our pipe is a demand. So I don't foresee any significant risks related specifically to Lyondell. Now to your question about how should we think about export markets. Obviously, things are really tight with diesel. The world demand and the draw from the Gulf Coast is heavy for diesel demand. So that impacts the price of the Gulf Coast, which draw -- tends to draw barrels to the Gulf Coast for sure. But you're also talking about many of the markets we're connected to are still premium markets that have to be supplied. So it all just starts working out in the netback equation for the refiners. And if one refiner wants to ship more barrels overseas, the diesel, the price has to change and the markets have to adapt because the reality is, the demand is still there and someone has to fill it. The beauty of our system is really the flexibility that we have, Gulf Coast origin, up to the group potentially, which hasn't made a lot of sense of late like it did last year because of exactly what you're talking about. There's more demand in the Gulf Coast for products. So we're seeing fewer moves from the Gulf Coast, up into the Mid-Continent. But the opposite can also occur, to some degree, where it actually draws. As Gulf Coast refiners export more, it can draw barrels from the Mid-Continent to places in Texas and even potentially further west. So there's a bit of a balance there, that the thing I would keep in mind is, at the end of our pipes, we're serving the demand that exists and that demand is not going away. So as the supplies shift and given the breadth of our system, we're able to adapt to that and keep those markets supplied from many different origins. We're not just, of course, single-threaded to the Gulf Coast. So that's the -- really one of the strengths of our system. Did that answer your question?

Theresa Chen: Yes. Thank you very much for the thorough responses.

Operator: . Our next question comes from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet: I just wanted to pivot a little bit here and talk about, I guess, your splitter here, where I think that the contract for the Corpus Christi condensate splitter is coming up in the not-too-distant future. And just wondering how you think about that asset at this point and when that expires, would you look to do another tolling arrangement, would you look to sell the asset, would you use the asset yourself. It seems like there's some pretty good economics there with diesel. And just wondering how you think about your options at that point.

Aaron Milford: We think we have a pretty good slate of options, given that, for the most part, we don't like to take a lot of commodity risk where it's not justified or we don't have expertise per se. So we recently did a tolling deal. Our customer pays us a fee, and then they're arranging the crude oil and then taking the offtake and making money doing so. So if we can toll it in a reasonable way, that's probably our preferred option, frankly. But at the same time, we're also developing a lot more expertise through the years. So if it came to we needed to run it, we could probably do that. Even though that's not our first -- maybe our first choice, I think we have the capability to do that if we chose to do it. So from the splitter side of things, how we think about it is the asset has gone up in value in terms of the money that you can make and the margin that is available with that asset. So we should have a number of options, including just renewing the toll that we have right now, to sort of sustain the economic benefit of that splitter to us. Which path we would take is a little uncertain right now. We just don't know. We're not at the point where decisions have been made, but we're not overly concerned about continuing to drive significant value from the splitter.

Jeremy Tonet: Got it. That's helpful context there. And maybe just kind of taking a step back in overall demand recovery. If you could just expand a bit more, I guess, on what trends you're seeing out there currently in your markets and pace of demand recovery and expectations over the balance of this year or further, if you willing to share. Just trying to get a sense for how that looks for you.

Aaron Milford: So you may recall, at the beginning of the year, we gave guidance that we thought, on a year-over-year basis, so 2022 for the year versus 2021 for the year, we expect volumes to increase 4%. And that's still where we expect it to be. So on a serial basis, we expect growth in our refined products volumes. And that growth, of course, is driven by recovery, which we're still seeing in some of our markets and also the contribution from our growth projects that we had brought on over the last few years. So we continue to expect growth of year-over-year, about 4%. We've got some markets up in the northern part of our system, frankly, that have been a little slower to recover, but they are recovering. And so we've got a pretty, I think, an optimistic outlook for what our volumes are going to grow this year versus last year.

Operator: Our next question comes from the line of Michael Lapides with Goldman Sachs.

Michael Lapides: And again, I mentioned this at the Analyst Day, congrats on the new role. Just a cost question. We all kind of know, and you talk a lot about kind of what the revenue per barrel increases are on both the index and on the competitive side for the refined product system, can you talk to a little bit -- to us a little bit in this kind of high inflationary market what you're expecting cost-wise this year and whether you think it stays elevated that way going into 2023?

Aaron Milford: Well, it's a good question, Michael, and thank you for the well-wishes as well. Inflation, it's interesting. We see pockets of our business today, where we're seeing some inflation, primarily on labor. Think about our maintenance capital, where we're doing work, hiring contractors. We are seeing some rate inflation there, although I wouldn't raise the alarm bell about the inflation. It's -- we're seeing it, but it's hard for us to really see how much that's going to translate or extrapolate or change from here. And then when you -- so we're seeing some of it, but again, I wouldn't raise any alarm bells on the expense side. Secondly, you have to combine what's happening on the inflationary front with a lot of the work we're doing to optimize our business. So when you look at overall expense growth for our business, we're shooting to come in well under inflation in total regardless of where that is because we're optimizing our business while, at the same time, experiencing some inflation, that we hope to offset most of. So we think we have a good equation for managing our costs as we move forward, even if we do see some inflation in certain parts of our business. So we're not changing our outlook with that. But we're going to have to wait and see to some extent as well how the rest of the year plays out.

Operator: Mr. Milford, there are no further questions at this time. I'll turn the call back to you. Please continue with your presentation or closing remarks.

Aaron Milford: Well, thank you all for your time today and your interest in Magellan. And I hope you guys have a great day.

Operator: That does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your line.