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spk06: Greetings and welcome to the Magellan fourth quarter 21 earnings call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question and answer session. At that time, if you have a question, please press the 1 followed by the 4 on your telephone. If at any time during the conference you need to reach an operator, please press star 0. As a reminder, this conference is being recorded Wednesday, February 2, 2022. I would now like to turn the conference over to Mike Mears, Chief Executive Officer. Please go ahead.
spk07: Well, good afternoon, and thank you for joining us today to discuss Magellan's fourth quarter financial results and our guidance for the new year. Before we get started, I'll 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, inform your own opinions about Magellan's future performance. Magellan finished 2021 with another strong quarter, generating financial and operational results that exceeded our expectations and solidified 2021 as a year of robust demand recovery for our services. Our CFO, Jeff Holman, will now review our fourth quarter financial results in general. Then I'll be back to discuss our guidance before answering your questions.
spk02: Thanks, Mike. 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 fourth quarter net income of $244 million, compared to $184 million in fourth quarter 2020. Adjusted earnings per unit for the quarter which excludes the impact of commodity-related mark-to-market adjustments, was $1.24, which, as Mike pointed out, exceeded our guidance for the quarter of $1.10. DCF for the quarter of $297 million was 10% higher than fourth quarter of 2020. And similarly to last quarter, the primary driver of that increase was additional contributions from our refined product segments. Pre-cash flow for the quarter was $291 million, resulting in pre-cash flow after distributions of $70 million. Full year 2021 DCF was $1.118 billion, approximately 7% higher than in 2020, resulting in a distribution coverage ratio for 2021 of 1.24 times. DCF per unit in 2021 was $5.14, about 10% higher than in 2020. This per unit perspective reflects the significant impact of our buyback program and underscores our ability to deliver per unit growth in excess of the top line DCF growth that our business experiences. I should note that the DCF per unit calculation I just mentioned is based on the weighted average number of units outstanding on the record dates related to the period. Full year free cash flow for 2021 was $1.316 billion. resulting in free cash flow after distributions of about $410 million for the year. 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 of the highlights of the fourth quarter results. Starting with our refined product segment, operating margin of $303 million for the quarter was approximately 27% higher than the 2020 period. Our refined products business continued to benefit from the recovery in travel, economic, and drilling activity in 2021, compared to the pandemic driven reductions experienced in 2020, as well as from the final revenue commitment ramp on our Texas expansion projects. Overall, refined transportation volumes were at 14% relative to the prior year period, with significant increases in all products. And on an absolute basis, volumes once again set a new quarterly record. Reflecting the sharp rebound in travel, aviation fuel once again saw an 80% plus increase versus the prior year period. Though as usual, I'll note for context that aviation fuel typically constitutes less than 10% of our overall volumes. Refined products revenues also benefited from the 3% overall average tariff increase that went into effect on July 1st of 2021. As a reminder, this 3% increase consisted of a 0.6% decrease to our index rates and an average increase of more than 4% to our remaining rates. As I imagine most of you are probably aware, the FERC recently revisited the index calculation. With the result, we will be reducing our index rates by about 1% effective March 2022, which Mike will discuss further in a few moments as part of our guidance discussion. Product margin was favorable compared to the fourth quarter of 2020, primarily due to higher gas liquids blending margins and volumes as a result of the better commodity environment and improved blending opportunities. In addition, we had lower unrealized losses in the current period related to our hedging activities. Turning to our crude oil business, fourth quarter operating margin was approximately $104 million, down 5% from the fourth quarter of 2020, due to reductions in some of our rates, lower volume shipped, and reduced storage revenue. Longhorn volumes of 250,000 barrels per day were in line with the prior year. While the story on Longhorn for most of 2021 has been the contract expirations on the pipeline in late 2020, the fourth quarter was a full year past that step change, resulting in pretty consistent performance on the line between the 2021 and 2020 periods. Volumes on our Houston distribution system decreased versus the prior year period and were lower than we had expected, primarily due to the delay in the startup of the new connecting pipeline, which we now believe will begin deliveries to us in early 2022. Just as a reminder, although we often see volatility in our Houston distribution system volumes between quarters, those volumes move at significantly lower rates and longer haul long-haul shipments, which means that their impact on our reported volumes and average rate is much greater than their impact on actual revenues. Which brings me to our average crude oil tariff rate. Even though the competitive environment we are currently operating in has led to generally lower tariffs across our crude pipes, the overall average rate per barrel shipped actually increased between periods due to a proportionately lower volume of those short haul Houston distribution movements at lower rates. Similar to last quarter, we also saw reduced storage revenues due to lower utilization and rates following recent contract expirations. You may recall that we entered numerous short-term contracts during the early period of the pandemic, and the market was in deep contango, and storage in general was in very high demand. As the short-term contracts have rolled off and the market has been pretty backward, we've seen lower rates for our storage services. Moving on to our joint ventures, Rich text volumes were approximately 300,000 barrels per day in the fourth quarter of 21 compared to nearly 350,000 barrels per day in 2020, partially due just to the timing of when our committed shippers have elected to move volume under their commitments, as well as due to the expiration of a few smaller commitments earlier in the year. Saddlehorn volumes increased to 235,000 barrels per day compared to about 165,000 barrels per day the year before, primarily as a result of new commitments in 2021 associated with the pipeline's expansion. 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 to us through mid-2024, with $108 million outstanding on our commercial paper program as of December 31st. Additionally, our next bond maturity isn't until 2025. The face value of a long-term debt as of the end of 2021 was $5.1 million, with a weighted average interest rate on that debt of about 4.4%. Our leverage ratio at the end of the quarter was a little less than 3.5 times for compliance purposes, which incorporates the gain we realized from the sale of part of our interest in Pasadena earlier in 2021. Excluding that gain, leverage would have been a little over 3.6 times, And it is really that metric, excluding the gain on sale, that we are looking to as we manage leverage, including, of course, the impact on leverage of our unit repurchase program. 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 fourth quarter, we repurchased nearly 1.1 million units at an average purchase price of $47.29 for a total spend of $50 million, bringing the cumulative amount of units repurchased during 2021 to 10.9 million units for $523 million. Since we began our buyback program in 2020, Magellan has repurchased $800 million worth of units under our $1.5 billion repurchase program The unit repurchases made over the past two years have decreased our units outstanding by about 7%, thereby, of course, increasing our DCF per unit by a similar amount, and in addition, contributing to better distribution coverage going forward. Of course, 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, 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 longstanding four times leverage limit and also that the timing of the proceeds from the independent terminal sale remains subject to the government review process. With that, I'll turn the call back over to Mike.
spk07: Thank you, Jeff. Turning to our outlook for the new year, this morning we announced DCF guidance of $1.075 billion for 2022. We recognize this guidance is a bit lower than the street was expecting, but considering that there is about $35 million of assumed reduced earnings associated with recently completed and pending asset sales, we have essentially forecast the remainder of our business to generate results very similar to our 21 actuals. While we expect continued growth in refined products demand, and healthy mid-year tariff increases this year. We further expect these positives to be offset by a few unfavorable items, including reduced revenues for both refined products and crude oil storage, which is a theme we've mentioned to you the last few quarters, as well as the $25 million overall favorable impact from the 2021 winter storms that we do not expect to occur in the new year. As usual, I'd like to spend the next few minutes walking you through the key assumptions we have used to develop our 2022 projections, which we hope will help you better understand how we're thinking about the new year. Starting with our refined product segment, which comprises about 70% of our operating margin, we assume that refined products pipeline shipments continue to increase during 2022 due to a combination of improved overall demand, as the economy, drilling, and travel in general continue to recover, as well as the full-year benefit of our Texas expansion projects, now that committed volumes have ramped up to their full commitment level. As a result, we expect refined product shipments to increase about 4% compared to 2021 results, driven by 4% higher gasoline, 2% higher distillate, and 15% higher aviation fuel demand. For sensitivity purposes, we ballpark estimate that every 1% change in total refined products transportation volumes represents about $10 million of DCF on an annual basis. In addition to volume, the average tariff rate for our refined products pipeline system is an important component to model this segment, especially in the current inflationary environment. Our current plan assumes that we will increase our refined products rates by an average of approximately 6% on July 1st. There are multiple components in the calculation of this average, so I'll briefly go through them. Currently, about 30% of our refined product shipments follow the FERC's index methodology for annual tariff adjustments, with the remaining 70% deemed to be competitive markets and are generally adjusted as market conditions allow. As Jeff mentioned, the FERC recently changed its methodology for the industry's index rates. For a bit of background, the index calculation has been based on the change in the producer price index plus 0.78%, with that adjustment going into effect on July 1st of 2021, resulting in a 0.6% decline in our index markets last year. Just a few weeks ago, the FERC adjusted the methodology to now be based on the change in producer price index minus 0.21%, so essentially 1% below the initial approach. This change will become effective on March 1st, so we will lower our index rates by 1% next month, then follow the typical July 1st cycle after that through the year 2025 using this new formula. In case of interest, we estimate that a negative 1% change in the index currently results in about $3 million annually to Magellan. As you may know, the preliminary change in PPI for 2021 is a positive 8.9%, which will result in an index rate increase of 8.7% on July 1st using this new methodology, which is the planned tariff increase for these markets. The remaining 70% of our refined markets are either interstate movements or markets that have been deemed to be workably competitive by the FERC. As a result, they are not subject to the index methodology, and we generally adjust these rates each year as competitive forces allow. We have been increasing our competitive rates in the 3 to 4 percent annual range over the last few years, which has been higher than the corresponding index change over the same timeframe. For instance, as we've already mentioned, the index declined by 0.6 percent last year, which, given the recent FERC index change discussed, will now be at a 1.6 percent decline. Comparatively, we increased our competitive market rates by more than 4 percent on average last year. While we'll continue to analyze our rates on a market-by-market basis to ensure we remain competitive, our guidance assumes that we increase the rates for the 70 percent of our market-based tariffs by approximately 5 percent on July 1st. I will point out that because of the complexity of our pipeline system, the average rate per barrel we report is based on a mixture of long-haul and short-haul movements, and therefore changes based on the actual point-to-point movements we make. In the new year, we expect more short-haul movements due to additional volumes of our East Houston to Hearn expansion project, as well as fewer barrels moving from Texas into the mid-continent. both of which result in lower overall average rates. In addition, we do not currently expect approximately $20 million of deficiency revenue recognized in 21 to recur again, which also negatively impacts the average rate per barrel as deficiencies represent revenue recognized with no related barrels. Considering these factors, we expect our overall average rate per barrel shift to remain relatively flat to 21 results, even though we intend to raise refined products tariffs by an average of 6% in mid 2022. Also, for our refined product segment, the commodity price environment is important as it directly impacts our gas liquids blending profits. We have hedged essentially all of our spring blending margin at this point at a 40 cent margin, which equates to about 50% of our total expected blending sales volume for the year. Between the margins we have already hedged and last week's forward curve for the unhedged volume, we currently expect an average funding margin of about 40 cents per gallon for 2022, which is similar to 2021 results, but slightly lower than the 45-cent average margin over the last five years. Following our typical approach, we would expect to begin hedging blending activity for the fall of 22 in the next few months once the markets become more liquid for the fall season. Moving to our crude oil segment, which comprises the remaining 30% of our operating margin, we expect volumes on our Longhorn pipeline to average 240,000 barrels per day, which is very similar to the 245,000 we averaged in 2021. We have recently added a new third-party commitment to Longhorn and a tariff rate which generally reflects the current market differentials, resulting in approximately 75% of the pipe's 275,000 barrel per day capacity being committed at this point with an average remaining life of six years. Although we prefer third parties to move products on our pipes whenever possible, any incremental movements above the committed level are expected to result from our marketing affiliates stepping in to fill the unused space as market conditions allow. But as we've discussed in the past, the profitability of these marketing activities closely reflects the prevailing Permian to Houston differential, which currently remains very low. Our other wholly-owned crude oil pipeline is the Houston distribution system, which as Jeff pointed out, can fluctuate between periods. We have recently connected our Houston distribution system to new long-haul pipelines moving crude oil to the Houston area. We expect volume on the HDS or the distribution system to rebound by more than 50% during 22 as more barrels utilize our extensive system that connect to all the refineries in the Houston and Texas City area. As a reminder, rates charged on the Houston distribution system are significantly lower than Longhorn due to the short distance move, which impacts the overall average crude oil rate per barrel that we report in our financials. With the expected volumes in 22, our average crude oil rate per barrel shipped should be closer to $0.60 per barrel this year versus $0.80 per barrel in 21, reflecting the incremental proportion of shorter haul movements. Concerning our joint venture pipelines, we expect shipments on bridge decks to average around 300,000 barrels per day during 2022, which is similar to activity in 21. At this point, BridgeTex has commitments for approximately 70% of the pipeline's 440,000 barrel per day capacity, with an average remaining life of four years. With the current low differential between the Permian and Houston, spot shipments generally remain uneconomical, so we expect shipments basically in line with commitment levels. For Saddlehorn, we expect to move about 230,000 barrels per day during 22, which is in line with current contracted levels. Based on the final step-up of commitments under the new contracts for the recent expansion of the line, Saddlehorn has commitments for 80% of the pipeline's 290,000 barrel per day capacity with an average remaining life of five years. On the expense side, we've discussed in the past that Magellan kicked off the initiative a few years ago to identify cost savings and efficiency opportunities throughout the organization. This initiative has served us well to ensure 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 initiatives, we currently expect total expenses inclusive of both operating expenses and G&A costs, to increase by about 2% in 2022. Concerning maintenance capital, we expect to spend around $80 million during 2022, which is very similar to last year's actuals. At Magellan, we believe that our most important social obligation is to safely and reliably transport and store the fuels that our nation relies on every day, while protecting the communities where we live and work. Our dedicated workforce spends significant time and effort each year to ensure the integrity of our assets. Between capital and expense, we expect to spend more than $200 million on maintenance and integrity work in 2022. As you are aware, both maintenance capital and expense are considered in determining distributable cash flow and free cash flow. As a quick reminder, we still await regulatory approval for the pending sale of our independent terminals announced last June. We continue to expect the transaction to close this year, although exact timing is still a bit unclear. For guidance purposes, we have assumed that we own these assets through the first half of the year. In summary, all of these key assumptions build up to our DCF guidance of $1.075 billion for 2022. Recognizing that investors value steady increases to the cash distribution, we currently target annual distribution growth for 2022 similar to the increase provided last year, which would result in distribution coverage of 1.2 times the amount necessary to pay cash distributions declared on the current unit cap for 2022. While we are not providing guidance beyond 2022, we do expect DCF growth for the next few years from the tailwinds of modest refined product demand growth, a higher inflationary period which will benefit tariff rates, and continued strength in commodity prices. Management continues to expect that free cash flow after distributions will generally be used to repurchase equity, subject to the considerations Jeff mentioned previously. As a result, DCF per unit is expected to grow at a greater rate than DCF, providing increased value for investors in the future. Although we have executed on substantial equity repurchase to date and expect to continue our equity repurchase strategy going forward, We also remain focused on developing attractive growth capital investments to create future value for our company. Based on projects already committed, we expect to spend approximately $50 million in 2022 on expansion capital. Following a successful open season, these estimates now include a 5,000 barrel per day expansion of our refined product system from Kansas to Colorado that should be operational by late 2022. In addition, the previously announced expansion of our New Mexico refined products pipeline is nearing completion and expect to be operational in April of this year. Both of these projects are fully underwritten by commitment from strong counterparties and demonstrate the flexibility of our network to step up to fill market supply gaps that may arise. As you know, the environment for large-scale capital investments has been challenging over the last few years. However, we expect to add more growth projects throughout the year, although most likely smaller scale like these recent pipeline expansions. As a result, we still expect our expansion capital spending to be close to $100 million for 2022 as additional projects are approved as the year progresses. Bottom line is we remain patient and committed to our disciplined investment approach and continue to look for opportunities to invest in attractive, low-risk projects that meet or exceed our six to eight times EBITDA multiple threshold. Before we open the phone lines, I would like to briefly comment on my announcement last week that I will be retiring from Magellan on April 30th. I've spent my entire career with the company and couldn't be more proud of the organization we've created over the last 20 years. My role as CEO for the last 11 years has been rewarding, and I sincerely appreciate the support I've received from the investor and analyst community. I truly believe Magellan is the best-in-class company in the energy space from almost every perspective, including financial performance, dedication, operational safety, and company culture. We have been intentional to build the company on these strong principles from the very beginning to ensure our long-term success. Aaron Milford, who is here with us today, will be my successor as president and CEO And I and our board of directors have complete confidence in his abilities to lead Magellan into the future. The investment community should be familiar with Aaron as he served as CFO prior to taking on his current COO responsibilities. Aaron has also spent his entire career at the company, and we have worked together closely for many years. His leadership capabilities, strategic vision, and disciplined approach should ensure a seamless transition. Magellan is in a strong financial position with a resilient business model and experienced management team that prepares us well for the future. And with that, operator, I will now open the call for questions.
spk06: Thank you. If you would like to register a question, please press the 1 followed by the 4 on your telephone. You will hear a three-tone prompt to acknowledge your request. If your question has been answered and you would like to withdraw your registration, please press the one followed by the three. Again, to register for a question, please press the one followed by the four. And our first question comes from Teresa Chen with Barclays. Please proceed.
spk03: Hello. Congratulations, Mike, on your retirement, and congratulations also to Aaron on the new role.
spk07: Thank you, Teresa.
spk03: Sure. I wanted to ask first on the refined product segment. So, Mike, just summing all of the puts and takes up and all your commentary about the many variables related to this, net-net 2022 relative to 2021 volumes up 4% tariffs flat for the transportation portion, correct?
spk07: That's correct.
spk03: Okay. And then for the butane blending business, so you've hedged all of spring at 40 cents, and it looks like you expect the fall to also be similar since the average for the year is 40 cents. And I was wondering why that may be given that the board curves seem to indicate a little bit more favorable spot margins from here.
spk07: Well, the curves are moving all the time, as you would expect. So, we've taken a point in time, and the forward curves net of the cost of RENs, which we have to acquire, is roughly 40 cents right now.
spk03: Okay. And just lastly, in terms of getting the proceeds for the sale of the Southeast Terminal's Is there an expectation that the buyer may have to divest something? What are the gating factors at this point for you to close by mid-year? Or do you expect that this could be kicked down the line further?
spk07: Well, I don't really want to comment on what the expectations are from the FTC because that's really a process between the buyer and the FTC. But we firmly believe that the that we're going to close, and we think it's highly likely we're going to close within the timeframe we have within our guidance. But that's probably all I can really say about the process at this point.
spk03: Got it. Thank you.
spk06: And our next question comes from Keith Stanley with Wolf Research. Please proceed.
spk08: Hi. Good afternoon. Could I start just on the buybacks and capital allocation? So how do you think about repurchases in the first half of the year, assuming you close the terminal sale mid-year? You'll have some excess free cash flow, but, you know, a big chunk of cash coming mid-year. Would you be willing to use short-term borrowings in the first half of the year to repurchase equity, just given your, you know, pretty decently below the leverage target, or is that not something you'd be interested in?
spk02: This is Jeff. We would be open to that in theory. It always comes down to specifics, so if you look at the times we've bought back, it has not always been with current free cash flow, and the real regulator will be leverage. And so we'll have one eye on leverage, and we'll have an eye on the proceeds and the timing there. There's other factors, too. We'll be looking at what kind of investment opportunities we see, and we'll be wanting to pay attention to how we're trading as well. Obviously, if there's a dislocation in the price, we might be incentivized to be a little bit more aggressive on repurchases, and the converse would be true as well. So in theory, yes. In practice, I think you'll see us be fairly measured as we have been in the past.
spk08: Got it. And then, Mike, thanks for all the detailed drivers for 2022. That was very helpful. I just want to clarify. So in the release, it was noted that UTain blending profits are expected to be higher year over year in 2022. I think the margins you gave were pretty similar, though. So is it fair to say that's a pretty small driver? And then similar question for the storage side of things. Should we think of that as a pretty small overall driver, in that case a negative driver for 2022?
spk07: Well, on the storage side, we are in a soft market at the moment. And as we've talked about before, many of our storage contracts are relatively short term, one or two years. And so we have, you know, frequent rotation of those contracts. And so in the current environment with a strong backwardation in the market, you know, it's a challenging market to recontract storage. So we expect that to be soft this year versus last year. And as we mentioned in our comments, it also, you know, if you look at 21, it was, you know, benefited early in the year from short-term contracts we put in place during the pandemic, which were pretty high rate contracts. So, you know, we expect this year to be soft in that regard. We don't expect it to persist long-term. You know, the market goes through cycles, and at some point we'll be back in a contango market, and we expect there to be recovery there. But in 2022, we do expect some softness there. With regards to butane blending, you know, I think year over year we are expecting an increase. Even though the margins are relatively the same, we are projecting a growth in blending volume that's going to drive that higher.
spk08: Got it. Thank you very much.
spk06: And our next question comes from Praneesh Satish with Wells Fargo. Please proceed.
spk09: Thanks, Mike. Congrats on your retirement. And Aaron, congrats on the new role. I just have two questions, I guess. First, you noted that you signed a new third-party contract on Longhorn. So just curious if you could talk about the contracting environment for Permian Crude and whether you see any green shoots forming. Are you talking to any other customers or do you think this was kind of a one-off contract addition?
spk07: you know, the contracting environment in the Permian is extremely tight. I mean, quite honestly, shippers don't have a huge incentive to make commitments when spot rates are as low as they are. And, you know, the long-term picture doesn't look like those differentials will grow significantly over the next year or two. In this case, you know, even though we've signed a contract on Longhorn at what I would characterize as marginal profitability, those barrels ultimately get into our distribution system where there's some value to us there. And I think with regards to prospective shippers, the access we have to multiple demand points along our distribution system attracts customers. And so that was one of the drivers behind their willingness to sign a contract. And our willingness, again, you know, we look at the entire pie when we're signing a contract. It's not just what we make on Longhorn. It's also what we make once a barrel gets to Houston. So all that factors into our decision to contract. But I would not consider that necessarily as something you would expect to be continuing at least for the next year or two to sign incremental contracts, which doesn't mean that our marketing affiliate isn't opportunistically taking advantage of shipper interest in getting from the Permian to Houston and into our distribution system. That will continue.
spk09: And I'm wondering if you could talk about the FERC's decision to lower the PPI adjuster from 0.78 to negative 0.21. And just whether you think that has broader implications in terms of the FERC maybe taking a less friendly approach to oil and gas pipelines. I mean, it's made up of majority Democratic commissioners now. So I'm curious for your views on that and whether you think there's any political motives behind the adjustments.
spk07: I don't think it's an indicator that there's a developing bias against pipelines. If you'll recall, when the initial decision was made a little over a year ago, the chairman issued a very strongly worded dissent against the decision. So, you know, we knew as an industry that the risk on rehearing existed. once a Democratic commission was in place, that they would move more in the direction of the commissioner's view than what the original order was, and that's what happened. I don't see that as a big shift in focus by the commission. You know, the arguments that the commission overturned on rehearing to lower the rate arguments that have strong arguments on both side it's really I don't believe a biased decision so I'll stop there I don't think there's a political motivation behind it thank you and our next question comes line of spirit dunas with credit suites please proceed
spk01: Thanks, operator. Afternoon, guys. Congrats again to Mike and Aaron. Wanted to go back to the guidance if we could quickly. I think a lot of the context was helpful and sort of bridging between full year 21 and 2022. I guess where I'm still struggling on bridging everything is when I look at your performance in the back half of 2021 specifically, right? So no URI impact there. And I annualize that. And then I, of course, back out, you know, 35 million for sale. I still have a delta of about $65 million between what that implies between that number and your guidance. And of course, you called out, I think the contract renewals on storage is kind of a big item. But to me, it still seemed like too big of a delta to sort of bridge that gap. So curious, if you look at it from a back half performance of 2021 perspective, Mike, can you help me sort of bridge that number a little bit better?
spk07: I'll try. I don't know exactly how you came up with your $65 million, but let me just comment on a couple of things. We've talked about the asset sales, which is roughly $35 million. We've talked about the winter storm effects, which is about $25 million. We really didn't talk about the lower Saddlehorn tariffs in detail, but when we recontracted Saddlehorn, we agreed to incremental rate reductions in exchange for volume over time and for long-term contracts. And so there's a little bit of a reduction in 22 from that rate reduction, which is about $10 million probably year over year. When we talk about the refined products volumes, there's a number of elements, we didn't go through those in great detail, that's dropping the average rate back down to basically equal with 21. And that's a significant move, but there's some specific reasons. One we mentioned is that there's a slightly higher proportion of lower or shorter-haul volumes there. But I'd also mention, and I think we mentioned it in the comments, last year we benefited from some long-haul movements from Houston up into the Mid-Continent. Due to some refinery issues in the mid continent that we aren't expecting to repeat. And I think materially, you know, we recognize deficiency revenue last year. Which affected rate per barrel that's not going to recur or I should say, we don't expect it to recur in 22. That's in the neighborhood of 20Million dollars all of that. We didn't spell out specifically. It's embedded in that. you know, the assumption that our average rate per barrel is going to be even last year. So, those positives for 21 versus 22 are what's bringing it down. It's not that we view as anything negative happening in 22 associated with rate per barrel. It's really just an offset of positives, I mean, that we had in 21. You know, all of that being said that should get us closer, I guess, to your 65 million dollar number. I didn't add all that up in my head, but. You know, those are probably the things that you're missing in your calculation.
spk02: Jeff, I might just add to, I mean, I think we haven't done the exercise you talked about, partly because we wouldn't consider it really totally a valid way to do it. There's enough seasonality in the business. If you look at the four quarters of the last year, the volumes are much stronger in the last six months than they were in the first six months. And some of that's going to recur. So I'd caution against trying to annualize the back half of last year just on its own.
spk01: Okay. Now, that's helpful. I think all those items together probably bridge that gap, so I appreciate the color there, guys. The second one, just a really quick one here, sounds like your expectation for buybacks is to utilize most or all that $575 million or so free cash flow throughout the year. And I guess just curious, what are some of the items that could come up that maybe change that view or change that allocation? Is there potential for M&A, even on sort of a smaller scale, bolt-on basis, to move in there? Just curious what other factors you're looking at potentially.
spk07: Well, certainly the opportunity for capital investment is something that we are actively looking for. Finding projects that have attractive returns is challenging, but we're looking. It's probably less focused on M&A, even though I'd never rule that out, It's probably more focused on internal development. So to the extent that an opportunity were to arise that has an attractive return, it would impact that. And then again, all the other caveats that Jeff mentioned, you know, the price of the equity, you know, those sorts of things will factor into that also. And so... I mean, it's not really more complicated than that.
spk01: No worries. Keep it simple. All right. That's perfect. Thanks, Mike. We'll see you guys at the analyst day.
spk06: And our next question comes from Jeremy Tonant with J.P. Morgan. Please proceed.
spk05: Hi. Good afternoon. Good afternoon. Congratulations, Mike, on a successful career. We'll miss you. And Aaron, best of luck taking the reins here. Just wanted to kind of start off one question here, really, and a few different facets to it, I guess. You know, the Permian growth is in the upswing again, and I was just wondering if you could walk us through the different permutations of how this impacts Magellan. be it increased drilling demand from diesel, more oil logistics, whether conversion of pipelines makes sense, or just trying to think through the different impacts, as well as maybe a more favorable environment when you look to roll those contracts?
spk07: Okay. Well, that's a broad question. Let me try to break it down into its pieces. I mean, first and foremost, I mean, we do see – you know, the most material benefit to us from increased drilling in the Permian is diesel demand on our refined product system. And so certainly the extent that that grows, we have a direct benefit through throughput on our West Texas system. On the crude oil side, you know, because there's such significant overcapacity today, the production's gonna have to grow quite a bit before you're going to see any material change in the differential from Midland to Houston and willingness for shippers to make any kind of commitments at firm rates. So obviously we haven't built any of that into a 22 plan. When we look out long term, you know, when you get out to 24 or 25, I think the prospects of that are start to improve. But again, trying to forecast what the world looks like three or four years from now is difficult to do. But, you know, there is potentially some benefit out there that capacity does start to tighten. And if that happens, then we would expect margins to widen. and shippers to perhaps be more interested in making some level of commitment. All of that's somewhat speculative, as I said, three or four years out. So, you know, we'll have to see how that goes. As far as repurposing pipes, you know, I'm sure everybody who has a Permian pipe is evaluating that. To the extent that someone does that doesn't have to be us. It can be anyone. It's going to benefit everyone else. I don't have any insight as to what other folks are doing. I can tell you that we continue to actively look at repurposing. And as I said in the last call, there's nothing actionable to talk about today. There may not be anything actionable to talk about for some time. But I can tell you that there's a lot of activity taking place within the company to try to put a project together to do that. And I would say that the probability of that is not zero, that there's some real opportunity here, but there's some real challenges to get it done. But we're focused on that. So, I mean, just stay tuned on how that develops.
spk05: Got it. Very helpful there. And one last one, if I could, just With regards to the Cushing storage market, I wonder if you could provide a bit more color there, the current environment, how that's, I guess, impacting your business.
spk07: Well, it's not impacting us to a large extent right now because we've got significant contracts. I don't have on the tip of my fingers the percentage of Cushing storage that's contracted, but most of it's contracted. And so we're not seeing any significant issue right now at Cushing. And the life of those contracts has a number of years left. So we're really dependent on what the market looks like when they expire, which is an eminent.
spk05: Got it. I actually had one last one just to touch on quick. I think there was some things reported out there with regards to – union uh issues with other energy companies and kind of impasses there and and you know that impact and maybe inflation you talked a lot about inflation before but just wondering specifically on the labor side if um you know there's anything to note there well there's nothing to note i mean we've we've you know implemented our salary increases this year we do have a union um
spk07: And that union contract is up for renewal. And, you know, we expect we're going to have an outcome that everyone will be happy with. Those negotiations really haven't started yet. I mean, as you may know, the way this works is there's a pattern negotiation that happens first. That's happening now, and we're all waiting for that to end before we start our negotiations. But we expect... that we're going to wind up in a place where everybody's happy at the end of that.
spk05: Got it. I'll leave it there. Thank you very much.
spk06: And the next question comes flying of Michael Lapis with Goldman Sachs. Please proceed.
spk04: Hey, guys. Thanks for taking my questions. Just curious. So, you know, you're expecting in kind of true free cash flow about 575 and 22 and a large chunk of that comes from the asset sale. Just curious on the debt side, what happens in 22? Do you use any of that 575 to pay down debt, or is that 575 available for either growth capex or unit buybacks or other forms of capital allocation? And how do you think you end the year or kind of how you're thinking about debt to EBITDA at the end of the year as we enter 23?
spk02: Yeah, well, we're not – Projecting really to use those proceeds for any specified purpose other than generally our expectation would be to use free cash flow to repurchase units. But that will depend on all those factors as we talked about. So depending on how those play out and what other growth projects show up, you know, on the off chance, as Mike mentioned, the M&A showed up, obviously we could use it for any of those purposes in it. If none of those show up and we don't undertake repurchase activity, we could repurchase units. I mean, excuse me, we could pay down debt, but that's not our first plan. It's kind of the last option for us, just if we don't like any of the other options in front of us. So we don't project increasing debt during the year based on what we see today. for sure. And if we used all the proceeds for repurchases, that would end up pretty much where it is now. And so you can calculate the leverage ratio from sort of projections. I don't have that number right in front of me right this minute, but that's the way we would be thinking about that, Michael.
spk04: Got it. Okay. And You made a little bit of a comment about M&A, and over the last couple of years, the last two to three, three to four years, you've done a host or a number of kind of small asset sales. Is there anything that when you look at the portfolio where you would look at it and say, hey, you know what? I could actually – like these types of assets, not specific ones, but types of assets, I'd much rather be a buyer of at this point in time, like things that – that when you look at the markets might look attractive in the M&A market today versus maybe where they were three or four years ago?
spk07: Well, certainly the market's probably more attractive than it was three or four years ago, but that's not saying much. Three or four years ago, it was astronomically high. We – To answer your question specifically, there's not a set of assets out there right now that we're targeting to say we have to go buy. We like the kind of assets we already have, refined products assets. A couple years ago, there were some of those in the market, but we felt that they were still too high, which is why we were a seller rather than a buyer. We'll continue to watch that. And if those assets come back to the market and the prices are more reasonable, then we might get into it. We're not looking to really diversify outside of what we do right now. We don't really feel like this is the time for us to make big bets on things outside of our space, especially since we have what we believe to be an attractive opportunity to buy back our equity. All of that's a point-in-time decision. I mean, you never know what opportunity might fall in our lap next week, and we'll evaluate it. But right now, we're not actively pursuing anything transformational out there.
spk04: Got it. Thank you, Mike. Thanks, guys. Much appreciated.
spk06: And our next question comes from James Carriker with U.S. Capital Advisors. Please proceed.
spk12: Hi, thanks, and congrats again to Mike and Erin. I had one clarifying question. Mike, you talked about it in the press release, about $100 million of growth capex, and then the official guidance in the financial schedule had a number in there for 50. So just wondering if you know what maybe the difference is there.
spk02: Yeah, that's just generic assumption about what we think will actually get done. You know, if we put only what we've committed, it'd be that lower 50 number. And we also have got to be kind of under billing what we actually expect to have happen. So during the year, you know, there's a number of projects we're evaluating that are at various stages of development that can, you know, toggle into being committed relatively soon. And as we kind of handicap the probabilities, we come up with an area, another 50 or so. And so we come up with that. about 100 number.
spk12: So that's the difference. Okay. I thought that might be the case. Just wanted to clarify. And then I guess kind of big picture question, and I know we've gotten away from talking about growth versus normal and ex-growth projects, but when you look at the 2022 refined product outlook, I guess taking into account growth project that you put into place, like how normal does that feel relative to say 2019 levels? Does that feel like we've fully caught up? Do you think there's still some parts of the economy holding back when you look at that 22 number?
spk07: Well, I don't have the numbers in front of me, but I think just directionally on gasoline, we aren't quite back to 2019 numbers. Diesel fuel is strong and probably above 2019 numbers. And jet fuel obviously still not back to 2019 numbers. But I don't have any kind of percentages on my fingertips here to give you on that. And when I say gasoline's not there, I'm not talking about a big miss. I'm talking about it's not above where we were in 2019. And I think And again, and I've talked about this before, it really gets into the geography. I said in the rural markets, it's there. In the cities, it hasn't quite gotten back there. I mean, you still have businesses that don't have people back to work, which is surprising to us, but it's true. And so I think there's still a little bit of a lag there.
spk02: And there are some minor things, like Mike said, on our system that are specific. I think overall for the markets we serve gasoline, we project to be pretty much back to those 19 levels. There's some ins and outs just based on things going with our system, contract roll-offs in small places here and there that can affect volumes, et cetera. So overall, really it's only aviation that continues to lag by the end of this year.
spk12: Okay. That's all helpful, Culler. I can say maybe one more in. One question is, when you guys put the West Texas expansion into service, you noted a 7X multiple with, you know, potentially significant additional upside. I assume that that's probably not in your guidance for 22. But I guess, what would it take to achieve some of that significant upside that you laid out when you went forward with that project?
spk07: Well, we do have some growth in our West Texas volumes in our guidance. But beyond that, and we haven't put it in our guidance, we have a number of initiatives underway in West Texas, attractive initiatives that potentially can bring material new volumes to our assets. I'm not going to go into the details of those, but I can tell you it's across the breadth of the markets we serve. We say West Texas, but we say all the time that it's not just West Texas that this pipeline serves. It's markets in Mexico, Arizona, New Mexico, are all connected to our system. There's opportunities really across that spectrum that we're pursuing. Again, we haven't built those opportunities into our guidance. Some of those opportunities are probably more than a 2022 type horizon. They're beyond that. But I think it's safe to say there's material upside with regards to our West Texas assets that we're looking at that we haven't built into 2022.
spk02: I might just also point back to Mike's earlier answer around drilling. As well because if drilling exceeds our expectations without any of those other initiatives Mike's talking about we can see further upside from that from that expansion project And just to clarify these initiatives would you be able to Do them without having to repurpose any pipes.
spk12: These are just with existing space on existing assets Well some of it is but
spk07: You know, there are what I'd call home run scenarios that would require repurposing assets, and we're actively working on those also. But even absent that, like I said, there's opportunities for growth.
spk12: Okay. Thanks a lot, and congrats again. Thank you.
spk06: And our next question comes from Tim Schneider with Citi. Please proceed.
spk11: Hey, good afternoon. Just a quick question. On the butane blending, can you remind us, what are you most exposed to on the rinse side? Is that D4, D6, or a combination of those?
spk10: It's really composite. When we look at it, we have to meet the percentages that are in the new RBOs. And as we hedge, we look at that as a tally to make sure that we're getting each of the specific types of rinse that we need. So we're exposed to essentially all of them at different points in time. So it's a composite basket for us.
spk11: Got it. And then in your assumptions right now, are you guys just using the forward curves for that? Or do you have your own kind of views on what that grid pricing is going to look like through 2022?
spk10: Yeah, we're looking at the forward curves and paying attention to what's happening in the market. we have, I would say, our own opinions about maybe directionally where that is, but for the most part, it's forward curves. And the other point to point out is that we've already got a significant amount of 2022 rent obligations hedged. I think it's around 70% of what we view our obligation for 2022 to be. So we do have some more to go hedge, but we've got a lot of that taken care of already.
spk11: And that's all inclusive of that. I think you said it was a 40 cent margin. Is that right?
spk10: That's a net margin. So that's the gross margin less our operating expenses, less the cost of rents on a per gallon basis, net 40 cents.
spk11: Okay. But that includes the 70% hedged?
spk10: Yes.
spk11: Okay. Got it. Sorry. I was just trying to reconcile that. Yeah, go ahead.
spk02: That's it. Okay. Yeah.
spk11: All right. Yeah, that's great. That's all I had. Thank you.
spk07: Operator, we probably have time for one more question.
spk06: There's no more questions. I'll turn the call back over to you, Mr. Mears. Please go ahead.
spk07: All right. All right. Well, thank you. Well, we appreciate your continued interest in Magellan. And we hope to see many of you at our Analyst Day next month. And until then, have a good day.
spk06: Thank you. That does conclude the call for today. We thank you for your participation and ask that you please disconnect your lines. Have a great day.
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