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.