Magellan Midstream Partners, L.P. (NYSE:MMP) Q4 2022 Earnings Call Transcript

Magellan Midstream Partners, L.P. (NYSE:MMP) Q4 2022 Earnings Call Transcript February 2, 2023

Operator: Greetings, and welcome to the Magellan Midstream Partners Fourth Quarter Earnings Conference Call. During the presentation, all participants will be in a listen only mode. Later we will conduct a question-and-answer session . As a reminder, this conference is being recorded, Thursday, February 2, 2023. It is now my pleasure to turn the conference over to Aaron Milford, CEO. Please go ahead.

Aaron Milford: Hello, and thank you for joining us today to discuss Magellan’s fourth quarter financial results and perhaps even more of interest, our outlook for the new year. 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. Magellan wrapped up the year with another solid quarter supported by record refined products transportation volumes and financial results that exceeded our expectations, excluding a noncash impairment taken in the quarter.

During 2022, we delivered over $1.3 billion of value to our investors via opportunistic equity repurchases and Magellan’s attractive cash distribution, marking 21 years of continuous annual distribution growth. I will now turn the call over to our CFO, Jeff Holman, to review our fourth quarter financial results versus the year ago period. Then I’ll be back to discuss our annual guidance for 2023 before answering your questions.

Jeff Holman: Thanks, Aaron. First, I’ll note, as usual, that 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 fourth quarter net income of $187 million compared to $244 million in fourth quarter of 2021. These results include the $58 million impairment of our investment in the Double Eagle Pipeline joint venture. Adjusted earnings per unit for the quarter, which excludes the impact of commodity related mark to market adjustments, was $1.06. Excluding the $0.28 negative impact of the Double Eagle impairment, adjusted earnings per unit was $1.34, exceeding our guidance of $1.22.

DCF for the quarter increased to $345 million, up $48 million from last year while free cash flow for the quarter was $324 million, resulting in free cash flow after distributions of $109 million. For the full year 2022, DCF was $1.128 billion, an increase of $10 million from 2021. DCF per unit in 2022 was $5.46, about 6% higher than in 2021. This per unit perspective reflects the significant impact of our buyback program and highlights our ability to deliver per unit growth in excess of the underlying DCF growth that our business experiences. Full year free cash flow for 2022 was $1.486 billion, resulting in free cash flow after distributions of $660 million for the year. A detailed description of quarter-over-quarter variances is available in the earnings release.

So as usual, I’ll just touch on a few highlights. Starting with refined products. Fourth quarter operating margin of $303 million was essentially flat with fourth quarter 2021. Record quarterly transportation volumes and higher average transportation rates from our core fee based transportation and terminaling activities offset unfavorable mark to market adjustments on our commodity hedges. Higher rates were driven primarily by the midyear 2022 increase in our tariffs of about 6% on average. In addition, rates in the current period continued to benefit from more long haul shipments, which move at higher rates. Similar to the third quarter, the increase in long haul shipments was driven largely by our customers using the extensive connectivity of our system to satisfy market demand in areas along our network that continued to be impacted by refinery outages.

Operating expenses for the refined segment increased about $6 million versus the prior year period, primarily due to less favorable product overages, which reduced operating expense as well as higher power costs, primarily as a result of the increase in long haul movements just mentioned. These unfavorable expense items were partially offset by a favorable property tax true-up in the current quarter. Product margin decreased between periods as favorable results from our gas liquids blending activities, which saw both higher margins and higher sales volume were more than offset by the recognition of additional unrealized losses on commodity hedges in fourth quarter 2022. Our realized blending margins increased year-over-year to about $0.55 per gallon versus closer to $0.45 per gallon in the prior year period.

Turning to our crude oil business. Fourth quarter operating margin increased to $128 million, nearly 24% higher than in the ’21 period. Longhorn volumes averaged just over 245,000 barrels per day, slightly down from 250,000 in the fourth quarter of 2021 due to lower marketing affiliate shipments, partially offset by higher committed volumes. Longhorn revenue actually increased overall as the margin we earn on committed barrels is currently higher than the margin we realized on marketing affiliate variables. Volumes on our Houston distribution system increased versus the prior year period in part due to higher tariff shipments resulting from a new pipeline connection in 2022. These shipments move at a lower rate than long haul volumes, so this increased HTS activity resulted in a lower average rate for the segment overall.

In addition, terminal throughput fees increased, partially as a result of more customers electing to move barrels and our simplified pricing structure for our services within the Houston area, as well as higher dock activity in the quarter driven by the recent increase in export demand. Crude oil product margin increased versus the prior year period as we again benefited from additional crude oil marketing opportunities. As we noted on our call last quarter, these opportunities involve different factors, such as quality or location differentials and are less ratable than our core transportation and terminaling business, but provide low risk returns that we continue to pursue when available. Moving on to our crude oil joint ventures. BridgeTex volumes were nearly 270,000 barrels per day in the fourth quarter of ’22, down from nearly 300,000 barrels per day in 2021, and Saddlehorn volumes averaged nearly 230,000 barrels per day, slightly lower than 235,000 barrels per day in the ’21 period.

For both of these pipelines, the decrease in volume is primarily due to the timing of when our committed shippers utilize our services and emphasizes the importance of take-or-pay commitments from quality counterparties to ensure we get paid regardless of our customers’ short term logistics decisions. From an equity earnings perspective, we want to again recognize additional deficiency revenue for both the BridgeTex and Double Eagle pipelines, resulting in an increase in equity earnings for the segment. It’s worth noting that although this recognition of deficiency revenue results in higher equity earnings, the 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.

Moving beyond the individual segments, there are just a few other items I’d like to highlight from our quarterly results. Depreciation, amortization and impairment expense increased primarily due to the previously mentioned impairment of our investment in Double Eagle. You’ll recall that the Double Eagle pipeline, which delivers condensate from the Eagle Ford basin directly to Corpus and indirectly to Houston through a connection to a third party pipeline was backed by long-term customer commitments when it began operations nearly 10 years ago. Those initial contracts expire later this year and our customers did not provide notice of their intention to extend their commitments as provided for in those contracts. Further, those customers have consistently shipped below the commitment levels and consequently paid deficiency payments, while current market rates for transportation out of the Eagle Ford are significantly lower than the rates provided for in their expiring contracts.

As a result, we recorded an impairment of our investment in Double Eagle during the fourth quarter. Finally, as everyone will remember, we sold our independent terminals in June, which, of course, resulted in lower income from discontinued operations in the current period. Moving on to capital allocation, balance sheet metrics and liquidity. First, in terms of liquidity, we continue to have our $1 billion credit facility available with the maturity of most of those commitments under that facility extended to 2027 during the fourth quarter. As of December 31st, the face value of our long term debt was still about $5 billion with $32 million of commercial paper outstanding. The weighted average interest rate on our debt remains about 4.4% with our next bond maturity in 2025.

And as a reminder, essentially all of our interest rates remain fixed, other than that small amount of commercial paper borrowings. Our leverage ratio at the end of the quarter was 3.2 times for compliance purposes, which incorporates the gain we realized on the sale of our independent terminals. Excluding that gain, leverage would have been about 3.6 times. As for capital allocation, our story hasn’t changed. We continue to believe it is important for us to execute a balanced capital allocation strategy using a combination of capital investments, cash distributions and equity repurchases, all while remaining committed to the financial discipline we are known for. We continue to execute on our buyback strategy during the quarter, repurchasing 1.9 million units at an average price of about $50 per unit for a total spend of $95 million.

For the full year 2022, we invested $472 million in unit repurchases, bringing the total since inception to nearly $1.3 billion. We continue to see unit repurchases as an important focus of our ongoing capital allocation efforts and we continue to expect free cash flow after distributions to generally be used to repurchase our equity. But as we are always careful to note, the timing, price and volume of any unit repurchases will depend on a number of factors, including expected expansion capital spending, available free cash flow, balance sheet metrics, legal and regulatory requirements, as well as market conditions and the trading price of our equity. And of course, we remain committed to a strong balance sheet and our longstanding 4 times leverage limit.

With that, I’ll turn the call back over to Aaron.

Photo by Grant Durr on Unsplash

Aaron Milford: Thanks, Jeff. Turning to our outlook for the new year. This morning, we announced DCF guidance of $1.18 billion for 2023, which is about 4.5% higher than our 2022 results. I’d like to spend a few moments walking you through the key assumptions used to develop our 2023 guidance to help you better understand how we’re thinking about the new year. Starting with our refined products segment, which comprises about 70% of our operating margin. We expect refined product shipments to be about 1% higher than the record annual volume moved in 2022 due to continued stable demand and contributions from small system expansions, including the expansion of our pipeline between Kansas and Colorado, which will come online in the first quarter of the year.

As discussed last quarter, we believe that most of our markets have essentially returned to their pre-pandemic levels while a few outliers in our larger metropolitan markets such as Kansas City and Minneapolis, remained slightly lower. It’s still not clear to us if these outlier markets will return to historical demand or if they are now at their new normal. These estimates assume drilling activity remains robust and that our nation’s economy does not slow notably. Both of which impact our diesel fuel demand. While not a part of our 2023 guidance, our current project to increase pipeline capabilities to El Paso is underway and expected to become operational in early 2024, which should contribute to volume growth next year. The other key metric for our refined products pipeline system is the average tariff we charge.

In our current forecast assumes we increase our refined products rates by an all-in average of approximately 8% on July 1st. For those who have been tracking the producer price index, you’re aware that the change in PPI is currently estimated to be an increase of approximately 13.5% based on the preliminary results through December of 2022. We’ve indicated to the investment community over the last few quarters our intention to be very thoughtful in our approach to tariff increases this year due to the unprecedented level of the allowable increase. Should we decide to not take the full allowed index within the 30% of our markets subject to the FERC index, we will retain the ability to make up the difference in the future period. The other 70% of our refined products markets not subject to the index will be adjusted according to market conditions.

We have not finalized our decisions that we will take effect on July 1st and do not plan to break out the components of the 8% all-in average assumed in our guidance today, but we’ll provide more detail later in the year once we finalize our rate decisions. For reference, every 1% change in either total transportation volume or the average tariff for our refined products pipeline system impacts DCF by approximately $10 million on a full year basis. Specific to our commodity activities, we have continued to make significant progress hedging our gas liquids blending with 70% of our 2023 blending now hedged. Between the margins we have already hedged and last week’s forward curve for the unhedged volume, we currently forecast an average blending margin of about $0.60 per gallon for the year, which compares favorably to our 2022 results of $0.50 per gallon and our five year average margin, which is closer to $0.45 per gallon.

Breaking down our ’23 estimates further, we have nearly 90% of spring activity hedged at expected margins of $0.70 per gallon and 40% of fall blending hedged with margins closer to $0.50. Our estimates for 2023 blending incorporate RIN costs of nearly $0.20 per gallon due to the ongoing high pricing environment for RINs. We also continue to pay close attention to moves in the basis differential between our NYMEX based hedges and the price of gasoline we sell in the markets located along our pipeline system in the middle of the country. Our projections currently include an average basis differential of a negative $0.10 per gallon, which is about double historical levels but $0.05 better than the average basis differential experienced in 2022.

Moving to our crude oil segment, which comprises the remaining 30% of our operating margin. We expect volumes on our wholly owned pipelines to increase about 20% over 2022 results, primarily related to the full year impact of higher shipments on our Houston distribution system from a recent pipeline connection. We also expect Longhorn pipeline shipments to increase, averaging approximately 245,000 barrels per day compared to 230,000 barrels per day in 2022. As discussed last quarter, we recently added a new third party commitment to Longhorn, resulting in approximately 80% of the pipe’s 275,000 barrel per day capacity being committed at this point with an average remaining life of six years. Similar to 2022, shipments on our joint venture pipelines are expected to be lower than commitment levels and customers will be paying deficiency payments as a result.

Specific to BridgeTex, we expect shipments to average around 215,000 barrels per day during 2023, about 40,000 barrels per day lower than 2022 average annual volume with even lower shipments during the first quarter based on recent customer activity. At this point, BridgeTex has commitments for nearly 65% of the pipeline’s 440,000 barrels per day of capacity with an average remaining life of three years with a few small commitments expiring last month. For Saddlehorn, we expect to move about 220,000 barrels per day during 2023, which is similar to 2022 shipments. Saddlehorn currently has commitments for approximately 80% of the pipeline’s 290,000 barrel per day capacity with an average remaining life of four years. We expect storage revenues to be lower in 2023 for both our refined products and crude oil storage assets, a theme we saw during 2022 as well.

Although we generally target longer term contracts for our storage business that are somewhat agnostic to short term price movements, the ongoing backward dated pricing curve has made it more difficult to renew expiring contracts. Further, the $20 million contribution we received from the independent terminals during 2022 will not repeat following our sale of those assets in June of last year. On the expense side, we’ve discussed in the past that Magellan kicked off an optimization initiative several years ago to identify efficiency opportunities throughout the organization. This initiative has served us well to ensure that we are operating as efficiently as possible especially considering the current inflationary environment while safeguarding the integrity of our assets.

With the benefit of these optimization efforts, as well as a few onetime costs we don’t expect to recur again in the new year, we currently expect total cash expenses to increase by about 2% in 2023. Concerning maintenance capital, we expect to spend around $90 million during 2023, which is 10% above last year’s actuals but not out of the normal range for our company. The higher annual estimate is simply based on the timing of specific project work with nearly $10 million in 2023 related to large onetime projects associated with a pipeline relocation and an electrical upgrade. Safe and reliable operations are critical to our success, and we spend significant time and effort each year to ensure the integrity of our assets and to protect the communities where we live and work.

In fact, consistent with recent years, we expect to spend in excess of $200 million on maintenance and integrity work in 2023, considering both capital and expense projects. As an aside, we also mentioned in today’s earnings release that our guidance assumes an average crude oil price of $80 per barrel for the year, which is consistent with recent futures pricing. For sensitivity purposes, we currently estimate that each $10 change in the price of crude oil will impact our DCF by approximately $35 million in 2023, primarily related to our unhedged gas liquids blending activities and the value of our pipeline tender deductions and product overages. In summary, all of these key assumptions build up to our DCF guidance of $1.18 billion for 2023.

Coupled with our currently planned 1% annual distribution growth, we expect distribution coverage of 1.38 times, resulting in more than $215 million of free cash flow after distributions that can be used to reinvest in the business, buyback equity or otherwise create additional value for our investors. Magellan remains committed to a balanced capital allocation approach. We continue to see opportunity to create value through repurchasing units, but distributions will remain an important component of our capital allocation plans. We plan to increase our annual distribution by 1% this year, similar to the past two years, which results in a yield of nearly 8% based on recent MMP trading prices. While we’re not providing specific financial guidance beyond 2023 at this time, we expect DCF to continue to grow modestly over the next few years.

Combining this modest underlying growth with our expectation to continue to repurchase units results in even higher growth potential for our distributable cash flow per unit as we have seen in recent years. For example, our DCF grew at an average annual rate of just under 4% between 2020 and 2022, while our DCF per unit grew at an annual average rate of just over 8% during the same period. This example, we believe, demonstrates the power in our capital allocation approach and our ability to create long term value for our investors through a healthy current distribution combined with the potential for capital appreciation as DCF per unit increases. Moving on to expansion capital. We remain intent on developing attractive investments to create future value for our company.

We currently expect to spend approximately $110 million in 2023 and $40 million in 2024 on expansion capital projects already underway. As you probably know, the largest project included in this spending profile related to the expansion of our refined products pipeline to El Paso, which as mentioned earlier, is expected to be operational in 2024. We continue to assess new opportunities to enhance Magellan’s footprint and expect to find incremental projects that leverage the flexibility of our extensive network, most likely around filling logistical gaps that may arise between market demand and available supply. You may recall that we’ve generally estimated around $100 million of expansion capital spending per year as a reasonable assumption for potential projects.

As just noted, we’re already planning to spend above that level for 2023. So depending on how successful we are in identifying near term new projects, a number closer to $150 million as a reasonable placeholder for this year. Even though we were aggressively pursuing additional projects to grow our DCF, we also remain committed to Magellan’s consistent disciplined investment approach. Quite simply, if the set of projects that meet or exceed our 6 times to 8 times EBITDA multiple thresholds remain relatively low. We intend to stay patient for the right opportunities and believe additional long term value is achievable through continued optimization of our existing assets and utilization of our other capital allocation tools. Operator, we are now ready to open the call for questions.

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Q&A Session

Operator: The first question comes from Theresa Chen of Barclays.

Theresa Chen: And Aaron, I just wanted to unpack that 8% refined products tariffs, understanding that you’re not giving the exact breakdown at this point. But just the way the math has to work given the 70-30 split between your competitive rates and your FERC index rates. Either you would be increasing close to the ceiling rate for your FERC rates or you would be increasing higher than that mid single digit clip that you’ve been doing for some time on the competitive rate. And I’m just wondering, have you gone through the process of talking with your major customers and just the price discovery process of what they’re willing to bear. And if you are willing to lean more aggressively on the competitive rates, are you confident that you wouldn’t be giving up some market share with this big increase?

Aaron Milford: And as I said in my comments, we haven’t made any final decisions about what we’re going to do on July 1st or for July 1st, I should say. But the 8% all-in rate, we think, is a good placeholder as we see things right now. And if you think about it in terms of we’re always talking to our customers, we have a good feel for what’s going on in the markets, but we do very much a market by market buildup of what we think is a rate increase that wouldn’t result in market share loss, frankly. That’s what we’re trying to manage a little bit is make sure that we’re increasing our rates, which in any event are going to be healthy. There are going to be healthy rate increases. But we are trying to make sure that we don’t push the envelope in such a way that we think that there’s a risk of losing market share.

So that’s the sensitivity that we have. If you look at that 8% all-in rate, we think that the combination of index and market rates that we may end up charging, which we think would reflect that 8% as we sit here today, we don’t think we’re running that risk. And what’s most likely to happen is our indexed markets will likely go up at a higher rate than our market based rates, but they’re both going to be healthy.

Theresa Chen: And then turning to the butane blending piece. As we think about the building blocks for the basis assumption of negative $0.10 for the year, clearly, January has been more favorable to our butane blending business than the fourth quarter. But we have several things going on. Clearly, there’s a lot of planned and unplanned downtime at the refineries in the Mid-Con, which helps you. But is set to go down sometime this quarter. So how should we think about the evolution of basis throughout the spring planting season?

Aaron Milford: Well, we think it’s going to remain volatile. That’s the simple answer to that. And you highlighted many of the reasons why we think it’s going to remain volatile. If you look at our expectations of negative $0.10 for 2023, we think that’s a reasonable assumption for sort of if you look through the whole year. Last year, we saw some bases really go our way and actually traded a positive, not a negative. We think that event could happen again this year. It’s hard to predict, but we just see a lot of volatility around it. So when we chose the minus $0.10, it was looking at the future markets and where we’re seeing them sort of sitting but it was also just considering the volatility in both directions that can happen.

So we just try to pick a reasonable number. We think there’s a good chance it’s going to be a little better this year than what we experienced last year. But in any event, it’s still elevated versus where it has historically traded by a pretty substantial margin. So it’s just us using our best estimate on what we see the full year turning out to look like, which we — or forecasting it to be slightly better than last year, but certainly not as good as it has been historically.

Operator: The next question comes from Praneeth Satish of Wells Fargo.

Praneeth Satish: On capital allocation, I’m just wondering if you’ve given thought to to raising the pace of distribution growth? I mean, EBITDA is going to be up — projected to be up 4% this year, but you’re only growing the distribution 1%. So it seems like there’s an active decision here not to grow distributions in line with cash flow growth. And I know you’re doing buybacks but I guess at what point would you consider accelerating distribution growth?

Aaron Milford: Yes, it’s an interesting question and we think about it, I think, fairly simply. The first thing I want to mention is we view a healthy distribution an important part of our overall value proposition. So for us, it’s really a question about what do you do incrementally from where you’re at, to your point, growing the distribution faster or emphasizing buybacks. That’s really the decision point that we have to make. And for us, it seems like adding materially to an already attractive distribution at spreads that are still to treasury is still wider than we think they should be. And we compare doing that to the opportunity to buy back units and when we compare the two, which one of those do we think will create the most long-term value for our investors long term.

And as we sit here right now, we still think buybacks make the most sense for us. The key I would make is that’s true right now. We’ve always tried to say things can change depending on what’s happening and where we see the best place to add value. So it’s important that we see both of them being very important. And if we look marginally right now, we see opportunity in our unit price. And as long as we see that opportunity, that’s where we’re going to focus. But it’s not set in stone, that’s just where we are right now.

Praneeth Satish: And then I think you mentioned that you’re getting higher rates on contracted capacity on Longhorn versus the marketing margin. So I’m just wondering if there’s plans to contract that small remaining piece of open capacity on Longhorn in 2023 or leave that open and contract it later when things potentially tighten?

Aaron Milford: And I think some of that difference. Well, first of all, if we have a counterparty that wants to pay us an attractive rate, as you look through time, we’re interested in talking about that. And it’s very counterparty specific. As I’ve mentioned in the past, people take different views of how much term they want to think about, how do they feel about capacity and different producers and customers have different motivations to either want to just sort of ride the spot market, so to speak or whether or not they want to make commitment for term to have surety of export out of the basin. So if we have counterparties out there that want to come up with a fair rate with some term on it, we’ll certainly consider it. So one of the reasons why the commitments are typically at higher rates is those are with customers that are taking a longer term view and they’re wanting to have term and we’re looking at that saying, if we’re going to look at this over a longer period of time, we need to make sure the rate is fair.

On the marketing side of the business, that’s much more of what’s happening today, much more of a spot market. So you don’t see that same term structure necessarily in the optimization that we’re trying to do with the spot movements in our marketing affiliate. So there’s just a little bit of difference in perspective and the types of customers that are interested in working through our marketing affiliate, and those that want to make sure they’ve got capacity out of the basin. And when you take those two different perspectives, you have different price sensitivities to both of them with the ones wanting term typically willing to pay a little more for that as a result. So does that answer your question, Praneeth?

Praneeth Satish: Yes, it does. Thank you.

Operator: The next question comes from Jeremy Tonet of JPMorgan.

Jeremy Tonet: Just wanted to come in on oil product margin a little bit more, if you might be able to dive in as far as what specific activities benefited 4Q? And do you see them repeating in 2023 and is that factored into the guidance?

Aaron Milford: So as we said, I’m trying to not be super specific because more specific we are the less opportunity we’re probably going to have, and I think it’s pretty much that simple. But the broad bucket, it was pretty broad, really, it’s quality differentials and it’s locational differentials. And those are where the opportunities are, and we do expect them to continue. We can’t predict the level but we expect to continue to find opportunities. But just to hopefully make this answer a little more satisfying, if you look at 2022, our accrued marketing activities contributed, call it, $25 million, $30 million, and we are — in our guidance basically assuming we’ll find a similar level of opportunities next year.

Jeremy Tonet: And then just want to pivot towards the CapEx. I think you said $150 million might be a reasonable placeholder there. I’m just wondering, I guess, the suite of potential growth project opportunities as you see it now. Would you say that’s kind of more or less than where it’s been maybe earlier in 2022? Just trying to see, I guess, how that could be — the growth opportunity as you see it might be evolving over time?

Aaron Milford: Well, I would say generally, the potential for investment opportunities for us. I would say today is probably, I mean, more optimistic today than it was even a year ago. And a lot of that really has to do with our customers and what they’re seeing and what they’re trying to accomplish in the conversations we’re having. I would not describe it as saying that we’re going to a completely new environment and we’re going back to the high levels that we saw in the recent past, I don’t see that but I do see some more optimism. And we have customers that certainly have some objectives that we can help them with. So I’m certainly more optimistic as I sit here today than I was a year ago, but we’re not in a totally different ZIP code.

So the $150 million this year was really driven by, we’re already spending in excess of $100 million in what we’ve already committed a really good projects and we expect to find a few more things to do this year. So we wanted to at least give you some idea of the magnitude of that. So does that answer your question?

Jeremy Tonet: Yes, that’s very helpful. And just if I could ask a quick bonus around one, if I could. Just if you had any opinion about the delta we’re seeing in the weekly versus monthly EIA product demand numbers and how if that impacts Magellan?

Aaron Milford: I really don’t have an opinion on it. We are focused on really what our customers are doing. And I just don’t have a direct opinion on it.

Operator: The next question comes from Spiro Dounis of Citi.

Spiro Dounis: I want to go back to the guidance, and I’ll try and keep it broad. We kind of looked over the last five or six years or so, and it looks like you guys have beaten your initial guidance every single year other than 2020, and I think there’s a pretty good reason to give you a pass on that one. But from an outsider’s perspective, it would seem like you all take a pretty conservative approach to guidance. So I guess I’m just curious, as you think about the guidance and maybe where some potential sources of upside surprise could be, anything you can kind of highlight? Maybe another way of asking is, what’s not in the guidance?

Aaron Milford: Well, I mean, a couple of things I would highlight. Everything that we foresee or expect, we’ve tried to reflect in this guidance. For example, the basis differential we just talked about, we tried to give you really clear guidance of what we assume there. We’re assuming it’s better than it was last year, but it’s still not as great as it was historically. We think that’s going to hold. But we’ll see how the year plays out on a volatility around basis. So that’s one area. Commodity prices, what’s going to happen with crude oil prices? We’re using an $80 strip basically for the year. Could they be better or worse? That’s an area we tried to give you some sensitivities around that based on what’s left to be unhedged and our tenders in our product.

So that’s an area that, depending on what commodity prices do in either direction that could influence where we end up. The long haul shipments, we do have some expectation that we’re going to continue to get some longer haul shipments. We’ve got a heavy slate of refinery maintenance is sort of expected in the first part of the year, we generally benefit. But then there’s the whole element of unexpected, unplanned outages and refineries have been running really hard for a very long time and we’ve seen a higher level of unplanned outages, frankly. And to the extent we have unplanned outages, that’s usually a good thing for us. And it’s difficult for us to predict what those unplanned outages are going to do. But if we start seeing a lot of unplanned outages, we would expect on average to benefit from that.

So we’ve tried to take into account what we can see on outages, but the unplanned outages are just very difficult to predict. It depends on where it happens, how long it happens, the nature of the outage itself. So it’s difficult to predict that that’s something that could traditionally be good for us. So I think it’s really that simple. It’s what happens with unplanned outages, what happens with the actual commodity markets, basis differential. And outside of those, we’ve really tried to provide the guidance that reflects what we think is going to happen this year.

Spiro Dounis: Second question is on storage. I guess I’m just curious, how would you characterize directionally how that market’s been moving maybe since the last year? I know pretty subdued here, but just curious what’s going to take to see the economics improve there? Is it really just a function of the futures curve at this point or is there something structural that could occur to kind of get that moving higher?

Aaron Milford: At the end of the day, I think on the margin, it’s the structure of the curve itself. I mean the reality is right now, when we go talk to the market about wanting to take storage, the forward curve is really difficult for those that are looking at future prices in order to justify taking stores. So I think the futures and the shape of the curve will have to move more back into a contango before we see what I would consider a market difference. Now there are some operational things. Exports wanting to lead the Gulf Coast, the continued growth in our HOU contract. There are some things that can create demand for our storage that could help us. But I think those are going to be overshadowed by just the overall forward market structure in terms of for things to really turn and look a lot, lot better for the storage market, we think that’s what has to happen.

With that said, we’ve had some left renewing some contracts at some rates that we think were pretty attractive. But those are being done for what I’m going to say, more operational and logistical purposes, more so than just an idea of I’m going to take storage out and the price is going to be higher tomorrow. We do have a set of customers that are less sensitive to that forward curve. But again, to change the real direction of the storage business, we’ll need to see the forward curve improve, but it doesn’t mean we’re lacking some opportunities to do a little better. And to your point is it the same now as it was last year? It feels about the same. Some days feel a little better, some days don’t. but it feels generally about the same.

Operator: The next question comes from Keith Stanley, Wolfe Research.

Keith Stanley: First, just thank you for all the disclosure. And Aaron, when you lay these things out, the transparency really is top notch versus your peers and actually remove some of the questions we all have. So first, I wanted to start on — just a follow-up on distribution growth. So I get the logic of the buybacks and growing DCF per unit. What’s a little interesting is your peers are doing the opposite, so they’re growing distributions faster, especially the peers doing less on buybacks, especially as the stocks have moved higher. So I’m curious if what the peers are doing weighs at all into your thinking on capital allocation over time as you’re competing for investor dollars, or are you more focused just on what makes sense for Magellan economically?

Aaron Milford: Well, first of all, thanks for the compliment on the transparency. We try, and I think we’re successful most of the time. So I do appreciate that being recognized. Now to your question about distribution growth, just to be brutally frank, we don’t think a lot about what our peers are doing in terms of their distribution growth and their buybacks because we’re not running their company, we’re not responsible for their company, they are, and they need to make their decisions based on what they see about their company. So we focus on what we’re trying to accomplish and what we see happening with our company. And we think it’s going to be really powerful to have a really healthy distribution. I mean it’s an almost 8% yield.

We’ve never cut it and we’ve always grown it for 21 years, and that’s important. And then when you compare that to our ability to drive what we think could be significant capital appreciation, if we grow our DCF per unit, you put that together, and we think we’ve got a really powerful value proposition for our company. Other people may view their value proposition and what they’re trying to accomplish differently. So we’re certainly aware of what others are doing but it doesn’t influence how we’re trying to run our company.

Keith Stanley: Second one, just a clarification, the oil sensitivity. So $10 per barrel change is $35 million. Is that holding all other variables like butane costs constant or it’s making an adjustment there in line with oil?

Aaron Milford: That’s an overall cash flow sensitivity to a $10 change. So it’s not holding everything constant as a result, it’s letting everything sort of flow through as it would flow through. But it’s very much a sensitivity, and Keith meant to be, what I would say, a barometer or thumb in the year than it is meant to be an exact number, but that’s the magnitude of an impact of a $10 change overall. The one thing I would highlight though is that we are considering the hedges we already have in place. So that sensitivity only applies to the things that we have yet to hedge in our tenders, and then also our product overages, which we collect those throughout the year. And so that’s what the difference is, unhedged butane and blending, tenders and product and a $10 change. So we have taken into account the hedges already in place.

Operator: The next question comes from John Mackay of Goldman Sachs.

John Mackay: I wanted to start maybe on the crude pipelines. We’ve seen, obviously, Permian overall kind of built from over from a top-down perspective. Corpus lines getting a little bit tighter, though, given the export pull. I’d just be curious, if you think we start to see maybe any benefits for the Houston bound pipes as Corpus starts to fill up or really, if that’s more of a kind of ’24 or ’25 story? Really just trying to think about how you’re thinking about those two markets and how the pipeline directions interact in 2023?

Aaron Milford: So I think you’ve summarized the current situation pretty well. There’s certainly a pull through Corpus for export purposes. And those pipes as a result are becoming more full, which should lead to barrels flowing over into the Houston pipes as production in the Permian continues to grow. So we think that’s a positive setup. If you actually look at where you might see that playing out or that expectation playing out is in the differential between Midland and Houston. If you look at the forward curves, it would all point to increasing differentials, that’s good for pipes. But the timeframe for that is, when you look at the forward curve, it’s in that ’24 to ’26 sort of time frame. So I think that aligns with the statement made in your question.

So I think it’s probably a little bit further down the road, more of the next year or slightly beyond before I think we start really seeing how that’s going to play out. But in the meantime, we’ve got really good contracts, so we’re insulated along the way. But I think you’re out in that ’24 to ’26 time frame, it’s going to depend on what production does and then what happens with export pull ultimately.

John Mackay: Maybe one probably smaller micro question. Just on the Double Eagle impairment, obviously, the overall number is small. Can you just talk about maybe what the financial impact on that kind of EBITDA basis could be?

Aaron Milford: So if you look at this year, we’re expecting distributions of around $10 million for Double Eagle this year. It’s a partial year because it expires later in the year based on our assumptions, but it’s about $10 million. Historically, it’s been closer to 15% on a full year basis.

Operator: The next question comes from Michael Cusimano of Pickering Energy Partners.

Michael Cusimano: I wanted to ask a little bit more about the assumptions in guidance. I think historically, Magellan hasn’t assumed much in terms of like product dislocations between markets within the guidance. So I’m just wondering, do you have better visibility today than maybe in years past or just maybe a more aggressive approach?

Aaron Milford: When you say product dislocation, just help me with exactly what you mean, do you mean price dislocation, do you mean inventory

Michael Cusimano: Like higher barrel miles in your products transport business?

Aaron Milford: That’s been an area that’s always been difficult for us to predict, whether it’s planned or unplanned. Refiners are typically pretty tied to the vest about when they plan to be down. So what’s happening is we’ve just seen a more consistent longer haul barrel and certainly when planned maintenance happens. So it just becomes a little easier for us to have an expectation that we’re going to get some benefit from that on those planned outages. So that’s really all it is. We’re just getting a little bit of visibility, a little more of a track record of seeing how it plays out. And when you combine that for this year, just a higher maintenance cycle for the refineries, we think that we’re going to benefit from that.

And we’ve included some of that into our guidance. And as I said previously, the unplanned part is what’s really difficult to predict. So we really don’t have anything in the guidance that says we’re planning X percent of unplanned, we don’t have that. But to the extent we can see turnarounds, we are trying to include some of that. So it’s probably less about visibility towards it, more so than it is a track record of us seeing it more consistently is what I would say.

Michael Cusimano: And then one more on the on the guidance. I was wondering if you made any like methodological adjustments, or if the provided sensitivities was just additional disclosure that you all wanted because I don’t think you’ve provided that in the past?

Aaron Milford: We have provided different sensitivities, or I should say we’ve tried to provide some sensitivities, especially around commodities and crude prices. So that’s not new for us. And there’s really no methodology change in how we think about guidance. We’re looking at it the same way. Again, the changes will be to the extent, for instance, on the longer haul pipe movement, because we assume we have more of a track record of seeing it, we’ve got some of that in it. But there isn’t any methodological change in how we’re producing guidance or thinking about guidance and the sensitivities aren’t new.

Operator: The next question comes from James Carreker of U.S. Capital Advisors.

James Carreker: In previous years, you’ve talked about the July 1 step up, but then also talked about due to mix shift headline number that you kind of print on tariff basis for the refined products segment may be lower than that. Just wondering if you’re seeing any of that dynamic as you look out to ’23, understanding it’s hard to predict planned and unplanned maintenance?

Aaron Milford: No, we’re not seeing anything.

James Carreker: And then I guess just also thinking about the higher than average rate increase planned here in July, however, it’s allocated between competitive and index markets. Assuming maybe another high number in ’24, is there a point at which you start becoming concerned about over earning risk as it relates to — I know the Page 700 has pros and cons, but over earning on that, if we get a couple of years of these mid to high single digit growth rates on the tariffs?

Aaron Milford: I wouldn’t say that we worry about it, but it is something that we’re aware of. I mean we certainly are aware of the calculations in the Page 700 and we try and be sensitive to them. At the end of the day, we’ll make our rate decisions considering what that says. But if we run a really good price, take really good care of our customers and you look at what our rates are as a percentage of the overall, the mix of things, it’s not that material in the grand scheme of things. So as long as we’re thoughtful — and I’m not worried about over-earning, but it’s something that we have to be aware of, obviously.

James Carreker: And maybe if I could fit one more. And you talked about how some of your markets are still below 2019 levels, and this maybe the new normal. But I guess any kind of sensitivity with respect to if certain markets did kind of get back to 2019, what upside could that be to volumes, whether it happens in ’23, ’24, 2030, whatever it is? How material would that be to your existing system volumes?

Aaron Milford: I really — first of all, I don’t think it’s going to be material one way or the other. So if you’re using that 1% sensitivity that we gave you, it’s probably within that bound with the rate and/or the volume, it’s probably within those bounds. But I don’t have that specific sensitivity right in front of me.

Jeff Holman: It’s just going to depend on the different components. Is it multiple metro areas, do they come all the way back, a part of the way back and there’s infinite kind of varieties there. So it’s

Aaron Milford: And the thing I would highlight is I don’t want to sort of sound overly pessimistic on those metropolitan areas. It’s not like they’re drastically different from where they were in 2019. They’re just down a little bit. But the reality is we would have expected them to come back and they just haven’t. and we’re trying to make everyone aware of that, but it’s not drastically different.

Operator: That was our final question. I’ll turn the call back over to you Mr. Milford for any closing remarks.

Aaron Milford: Well, thank you for your time today. We’re pleased with the solid results generated by Magellan in 2022 and look forward to an even stronger financial performance in the year ahead. We remain committed to running our business responsibly, while maintaining our proven financial discipline and balanced capital allocation strategy to maximize long term value for our investors. On behalf of our company, we appreciate your continued support and hope you have a nice day. Thank you.

Operator: This does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines. Thank you, and have a good day.